Empire District Electric (EDE) 10-Q 2013 Q1 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

x  Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2013

or

o  Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                              to                         .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Kansas (State of Incorporation) 44-0236370 (I.R.S. Employer Identification No.)

602 S. Joplin Avenue, Joplin, Missouri (Address of principal executive offices) 64801 (zip code)

Registrant’s telephone number: (417) 625-5100

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o  No x

As of April 30, 2013, 42,668,138 shares of common stock were outstanding.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

		PAGE
	Forward Looking Statements	3
Part I -	Financial Information:
Item 1.	Financial Statements:
	a.Consolidated Statements of Income	4
	b.Consolidated Balance Sheets	6
	c.Consolidated Statements of Cash Flows	8
	d.Notes to Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
	Executive Summary	30
	Results of Operations	32
	Rate Matters	39
	Competition and Markets	40
	Liquidity and Capital Resources	40
	Contractual Obligations	44
	Dividends	44
	Off-Balance Sheet Arrangements	45
	Critical Accounting Policies and Estimates.	45
	Recently Issued Accounting Standards.	45
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	47
Part II -	Other Information:
Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds — (none)
Item 3.	Defaults Upon Senior Securities - (none)
Item 4.	Mine Safety Disclosures - (none)
Item 5.	Other Information	48
Item 6.	Exhibits	48
	Signatures	49

2

FORWARD LOOKING STATEMENTS

Certain matters discussed in this quarterly report are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, impacts from the 2011 tornado, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like “anticipate”, “believe”, “expect”, “project”, “objective” or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include:

·weather, business and economic conditions, recovery and rebuilding efforts relating to the 2011 tornado and other factors which may impact sales volumes and customer growth;

·the costs and other impacts resulting from natural disasters, such as tornados and ice storms;

·the amount, terms and timing of rate relief we seek and related matters;

·the results of prudency and similar reviews by regulators of costs we incur, including capital expenditures, fuel and purchased power costs and Southwest Power Pool (SPP) regional transmission organization (RTO) expansion costs, including any regulatory disallowances that could result from prudency reviews;

·legislation and regulation, including environmental regulation (such as NOx, SO2, mercury, ash and CO2) and health care regulation;

·competition and markets, including the SPP Energy Imbalance Services Market and SPP Day-Ahead Market;

·electric utility restructuring, including ongoing federal activities and potential state activities;

·volatility in the credit, equity and other financial markets and the resulting impact on our short term debt costs and our ability to issue debt or equity securities, or otherwise secure funds to meet our capital expenditure, dividend and liquidity needs;

·the effect of changes in our credit ratings on the availability and cost of funds;

·the performance of our pension assets and other post employment benefit plan assets and the resulting impact on our related funding commitments;

·the periodic revision of our construction and capital expenditure plans and cost and timing estimates;

·our exposure to the credit risk of our hedging counterparties;

·changes in accounting requirements (including the potential consequences of being required to report in accordance with IFRS rather than U. S. GAAP);

·unauthorized physical or virtual access to our facilities and systems and acts of terrorism, including, but not limited to, cyber-terrorism;

·the timing of accretion estimates, and integration costs relating to completed and contemplated acquisitions and the performance of acquired businesses;

·rate regulation, growth rates, discount rates, capital spending rates, terminal value calculations and other factors integral to the calculations utilized to test the impairment of goodwill, in addition to market and economic conditions which could adversely affect the analysis and ultimately negatively impact earnings;

·the success of efforts to invest in and develop new opportunities;

·the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs;

·interruptions or changes in our coal delivery, gas transportation or storage agreements or arrangements;

·operation of our electric generation facilities and electric and gas transmission and distribution systems, including the performance of our joint owners;

·costs and effects of legal and administrative proceedings, settlements, investigations and claims; and

·other circumstances affecting anticipated rates, revenues and costs.

All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. New factors emerge from time to time and it is not possible for management to predict all such factors or to assess the impact of each such factor on us.  Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.

We caution you that any forward-looking statements are not guarantees of future performance and involve known and unknown risk, uncertainties and other factors which may cause our actual results, performance or achievements to differ materially from the facts, results, performance or achievements we have anticipated in such forward-looking statements.

3

PART I.  FINANCIAL INFORMATION

Item 1. Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Three Months Ended
	March 31,
	2013			2012
	(000’s except per share amounts)
Operating revenues:
Electric	$	128,762		$	119,726
Gas	20,493			15,683
Other	1,885			1,735
	151,140			137,144
Operating revenue deductions:
Fuel and purchased power	45,303			45,229
Cost of natural gas sold and transported	11,925			8,581
Regulated operating expenses	27,137			23,348
Other operating expenses	794			598
Maintenance and repairs	9,157			9,124
Loss on plant disallowance	2,409			—
Depreciation and amortization	16,100			14,935
Provision for income taxes	7,454			6,084
Other taxes	9,003			8,435
	129,282			116,334
Operating income	21,858			20,810
Other income and (deductions):
Allowance for equity funds used during construction	526			50
Interest income	508			179
Provision for other income taxes	(28		)	(115		)
Other - non-operating expense, net	(289		)	(227		)
	717			(113		)
Interest charges:
Long-term debt	9,951			10,654
Short-term debt	47			30
Allowance for borrowed funds used during construction	(305		)	(48		)
Other	252			257
	9,945			10,893
Net income	$	12,630		$	9,804
Weighted average number of common shares outstanding - basic	42,564			42,047
Weighted average number of common shares outstanding — diluted	42,587			42,075
Total earnings per weighted average share of common stock — basic and diluted	$	0.30		$	0.23
Dividends declared per share of common stock	$	0.25		$	0.25

See accompanying Notes to Consolidated Financial Statements.

4

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Twelve Months Ended
	March 31,
	2013			2012
	(000’s except per share amounts)
Operating revenues:
Electric	$	519,690		$	515,641
Gas	44,659			41,124
Other	6,745			6,521
	571,094			563,286
Operating revenue deductions:
Fuel and purchased power	178,971			191,268
Cost of natural gas sold and transported	21,977			19,302
Regulated operating expenses	98,160			89,075
Other operating expenses	2,926			2,221
Maintenance and repairs	40,476			40,923
Loss on plant disallowance	2,409			150
Depreciation and amortization	61,612			61,138
Provision for income taxes	35,466			32,886
Other taxes	31,828			30,426
	473,825			467,389
Operating income	97,269			95,897
Other income and (deductions):
Allowance for equity funds used during construction	1,623			343
Interest income	1,300			712
Benefit (provision) for other income taxes	25			(366		)
Other - non-operating expense, net	(1,973		)	(1,224		)
	975			(535		)
Interest charges:
Long-term debt	39,488			42,603
Short-term debt	205			85
Allowance for borrowed funds used during construction	(1,038		)	(243		)
Other	1,083			63
	39,738			42,508
Net income	$	58,506		$	52,854
Weighted average number of common shares outstanding - basic	42,385			41,946
Weighted average number of common shares outstanding — diluted	42,401			41,968
Total earnings per weighted average share of common stock — basic and diluted	$	1.38		$	1.26
Dividends declared per share of common stock	$	1.00		$	0.57

See accompanying Notes to Consolidated Financial Statements.

5

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	March 31, 2013		December 31, 2012
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	2,181,257	$	2,176,188
Natural gas	70,192		69,851
Other	38,188		37,983
Construction work in progress	82,086		56,347
	2,371,723		2,340,369
Accumulated depreciation and amortization	694,166		682,737
	1,677,557		1,657,632
Current assets:
Cash and cash equivalents	3,170		3,375
Restricted cash	1,772		4,357
Accounts receivable — trade, net of allowance of $2,109 and $1,388, respectively	48,710		38,874
Accrued unbilled revenues	20,361		23,254
Accounts receivable — other	8,430		13,277
Fuel, materials and supplies	52,140		61,870
Prepaid expenses and other	21,738		21,806
Unrealized gain in fair value of derivative contracts	900		96
Regulatory assets	7,685		6,377
	164,906		173,286
Noncurrent assets and deferred charges:
Regulatory assets	237,942		243,958
Goodwill	39,492		39,492
Unamortized debt issuance costs	7,440		7,606
Unrealized gain in fair value of derivative contracts	256		191
Other	8,180		4,204
	293,310		295,451
Total Assets	$	2,135,773	$	2,126,369

(Continued)

See accompanying Notes to Consolidated Financial Statements.

6

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	March 31, 2013		December 31, 2012
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 42,646,040 and 42,484,363 shares issued and outstanding, respectively	$	42,646	$	42,484
Capital in excess of par value	631,777		628,199
Retained earnings	49,100		47,115
Total common stockholders’ equity	723,523		717,798
Long-term debt (net of current portion):
Obligations under capital lease	4,374		4,441
First mortgage bonds and secured debt	487,550		487,541
Unsecured debt	199,662		199,644
Total long-term debt	691,586		691,626
Total long-term debt and common stockholders’ equity	1,415,109		1,409,424
Current liabilities:
Accounts payable and accrued liabilities	50,767		66,559
Current maturities of long-term debt	554		714
Short-term debt	23,000		24,000
Regulatory liabilities	3,542		3,089
Customer deposits	12,238		12,001
Interest accrued	13,163		5,902
Other current liabilities	764		—
Unrealized loss in fair value of derivative contracts	1,905		3,403
Taxes accrued	8,314		2,992
	114,247		118,660
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	136,528		134,269
Deferred income taxes	307,660		301,967
Unamortized investment tax credits	18,617		18,897
Pension and other postretirement benefit obligations	121,697		120,808
Unrealized loss in fair value of derivative contracts	3,307		3,819
Other	18,608		18,525
	606,417		598,285
Total Capitalization and Liabilities	$	2,135,773	$	2,126,369

See accompanying Notes to Consolidated Financial Statements.

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three Months Ended
	March 31,
	2013			2012
	($-000’s)
Operating activities:
Net income	$	12,630		$	9,804
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	16,813			20,846
Pension and other postretirement benefit costs, net of contributions	3,423			1,035
Deferred income taxes and unamortized investment tax credit, net	5,243			6,495
Allowance for equity funds used during construction	(526		)	(50		)
Stock compensation expense	1,351			871
Loss on plant disallowance	2,409			—
Reverse gain on sale of assets	1,236			—
Non-cash loss on derivatives	7			—
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	(640		)	6,795
Fuel, materials and supplies	7,563			46
Prepaid expenses, other current assets and deferred charges	119			(1,281		)
Accounts payable and accrued liabilities	(19,497		)	(18,254		)
Interest, taxes accrued and customer deposits	12,820			10,850
Other liabilities and other deferred credits	1,126			1,970
Net cash provided by operating activities	44,077			39,127
Investing activities:
Capital expenditures — regulated	(37,398		)	(30,355		)
Capital expenditures and other investments — non-regulated	(362		)	(699		)
Restricted cash	2,585			—
Net cash used in investing activities	(35,175		)	(31,054		)
Financing activities:
Proceeds from issuance of common stock, net of issuance costs	2,764			2,230
Net short-term borrowings/(repayments)	(1,000		)	10,500
Repayment of first mortgage bonds	—			(13,200		)
Dividends	(10,644		)	(10,514		)
Other	(227		)	(228		)
Net cash used in financing activities	(9,107		)	(11,212		)
Net decrease in cash and cash equivalents	(205		)	(3,139		)
Cash and cash equivalents at beginning of period	3,375			5,408
Cash and cash equivalents at end of period	$	3,170		$	2,269

See accompanying Notes to Consolidated Financial Statements.

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

We operate our businesses as three segments:  electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly-owned subsidiary which provides natural gas distribution to customers in 48 communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business.

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2012, of which there were none.

Note 2 - Recently Issued and Proposed Accounting Standards

Balance Sheet Offsetting:  In December 2011, the FASB amended the guidance governing the offsetting, or netting, of assets and liabilities on the balance sheet.  Under the revised guidance, an entity is required to disclose both the gross and net information about instruments and transactions that are eligible for offset on the balance sheet, as well as instruments or transactions subject to a master netting agreement. This standard is effective for annual periods beginning after January 1, 2013. We implemented this standard in the first quarter of 2013 and it did not have a material impact on our results of operations, financial position or liquidity.

Note 3— Regulatory Matters

On February 27, 2013, the MPSC approved a joint settlement agreement for our 2012 Missouri rate case. The agreement provides for an annual increase in base revenues for our Missouri electric customers in the amount of approximately $27.5 million, effective April 1, 2013, and the continuation of the current fuel adjustment mechanism. The agreement also includes an increase in depreciation rates, recovery of deferred tornado costs over the next ten years and the continuation of tracking mechanisms for expenses related to employee pension, retiree health care, vegetation management, and Iatan 2, Iatan Common and Plum Point operating and maintenance costs. In addition, the agreement includes a write-off of approximately $3.6 million, consisting of a $2.4 million disallowance for the prudency of certain construction expenditures for Iatan 2 and a $1.2 million regulatory reversal of a prior period gain on sale of our Asbury unit train, which is included in regulated operating expenses. We also agreed not to implement a Missouri general rate increase prior to October 1, 2014.

The following table sets forth the components of our regulatory assets and liabilities on our consolidated balance sheet (in thousands).

9

Regulatory Assets and Liabilities

	March 31, 2013		December 31, 2012
Regulatory Assets:
Current:
Under recovered purchased gas costs — gas segment(1)	$	764	$	1,689
Under recovered electric fuel and purchased power costs(1)	927		1,196
Other(1)	5,994		3,492
Regulatory assets, current(1)	7,685		6,377
Long-term:
Pension and other postretirement benefits(2)	133,539		136,480
Income taxes	47,297		48,759
Deferred construction accounting costs(3)	16,167		16,277
Unamortized loss on reacquired debt	10,910		11,078
Unsettled derivative losses — electric segment	4,748		6,557
System reliability — vegetation management	7,460		8,340
Storm costs(4)	4,437		4,223
Asset retirement obligation	4,492		4,430
Customer programs	3,756		3,916
Unamortized loss on interest rate derivative	978		989
Other	589		584
Deferred operating and maintenance expense	2,154		2,011
Under recovered electric fuel and purchased power costs	1,415		314
Regulatory assets, long-term	237,942		243,958
Total Regulatory Assets	$	245,627	$	250,335

	March 31, 2013		December 31, 2012
Regulatory Liabilities:
Current:
SWPA payment for Ozark Beach lost generation(1)	$	2,927	$	2,774
Other(1)	615		315
Regulatory liabilities, current(1)	3,542		3,089
Long-term:
Costs of removal	85,528		83,368
SWPA payment for Ozark Beach lost generation	18,583		19,467
Income taxes	11,617		11,972
Deferred construction accounting costs — fuel	7,975		8,011
Unamortized gain on interest rate derivative	3,328		3,371
Pension and other postretirement benefits(5)	1,635		2,007
Over recovered electric fuel and purchased power costs	5,954		5,826
Over recovered purchased gas costs — gas segment	1,908		247
Regulatory liabilities, long-term	136,528		134,269
Total Regulatory Liabilities	$	140,070	$	137,358

(1)  Reflects over and under recovered costs of the current portion of regulatory assets or liabilities detailed in the long term sections below expected to be returned or recovered, as applicable, within the next 12 months in rates.

(2) Primarily reflects regulatory assets resulting from the unfunded portion of our pension and OPEB liabilities and regulatory accounting for EDG acquisition costs. Approximately $0.1 million in pension and other postretirement benefit costs have been recognized since January 1, 2013 to reflect the amortization of the regulatory assets that were recorded at the time of the EDG acquisition of the Aquila, Inc. gas properties.

(3) Balances as of March 31, 2013	Deferred Carrying Charges		Deferred O&M		Depreciation		Current			Total
Iatan 1	$	2,657	$	1,330	$	1,611	$	(171	)	$	5,427
Iatan 2	3,805		4,126		2,674		(224		)	10,381
Plum Point	64		183		158		(46		)	359
Total										$	16,167

Balances as of December 31, 2013	Deferred Carrying Charges		Deferred O&M		Depreciation		Current			Total
Iatan 1	$	2,678	$	1,339	$	1,622	$	(170	)	$	5,469
Iatan 2	3,821		4,155		2,685		(224		)	10,437
Plum Point	64		195		158		(46		)	371
Total										$	16,277

10

(4)  Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado.

(5) Includes the effect of costs incurred that are more or less than those allowed in rates for the Missouri (EDE and EDG) and Kansas (EDE) portion of pension and other postretirement benefit costs. Since January 1, 2013, regulatory liabilities and corresponding expenses have been reduced by approximately $0.2 million as a result of ratemaking treatment.

Note 4— Risk Management and Derivative Financial Instruments

We engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain predictability. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.

All derivative instruments are recognized at fair value on the balance sheet with the unrealized losses or gains from derivatives used to hedge our fuel costs in our electric segment recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.

Risks and uncertainties affecting the determination of fair value include:  market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instrument in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our Consolidated Statement of Income and subject to our fuel adjustment clause.

As of March 31, 2013 and December 31, 2012, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

ASSET DERIVATIVES		March 31,		December 31,
Non-designated hedging		2013		2012
instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	79	$	3
	Non-current assets and deferred charges - other	—		17
Natural gas contracts, electric segment	Current assets	821		93
	Non-current assets and deferred charges	256		174
Total derivatives assets		$	1,156	$	287

LIABILITY DERIVATIVES
Non-designated as hedging instruments		March 31,		December 31,
due to regulatory accounting		2013		2012
Natural gas contracts, gas segment	Current liabilities	$	—	$	104
Natural gas contracts, electric segment	Current liabilities	1,905		3,299
	Non-current liabilities and deferred credits	3,307		3,819
Total derivatives liabilities		$	5,212	$	7,222

Electric

At March 31, 2013, approximately $1.1 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months.

11

The following tables set forth “mark-to-market” pre-tax gains/(losses) from non-designated derivative instruments for the electric segment for each of the periods ended March 31, (in thousands):

Non-Designated Hedging Instruments	Balance Sheet	Amount of Gain / (Loss) Recognized on Balance  Sheet
— Due to Regulatory Accounting	Classification of Gain /	Three Months Ended					Twelve Months Ended
Electric Segment	(Loss) on Derivative	2013		2012			2013			2012
Commodity contracts	Regulatory (assets)/liabilities	$	2,421	$	(2,302	)	$	(2,275	)	$	(9,899	)
Total Electric Segment		$	2,421	$	(2,302	)	$	(2,275	)	$	(9,899	)

Non-Designated Hedging Instruments	Statement of Income	Amount of Gain / (Loss) Recognized in Income  on Derivative
— Due to Regulatory Accounting	Classification of Gain /	Three Months Ended						Twelve Months Ended
Electric Segment	(Loss) on Derivative	2013			2012			2013			2012
Commodity contracts	Fuel and purchased power expense	$	(114	)	$	(24	)	$	(4,075	)	$	(2,416	)
Total Electric Segment		$	(114	)	$	(24	)	$	(4,075	)	$	(2,416	)

We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to fair value accounting because they qualify for the normal purchase normal sale exemption. We have a process in place to determine if any future executed contracts that otherwise qualify for the normal purchase normal sale exception contain a price adjustment feature and will account for these contracts accordingly.

As of March 31, 2013, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2013 and for the next four years are shown below at the following average prices per Dekatherm (Dth).

			Dth Hedged
Year	% Hedged		Physical	Financial	Average Price
Remainder 2013	60	%	1,630,000	3,050,000	$	5.146
2014	39	%	460,000	3,540,000	$	4.741
2015	20	%		1,910,000	$	4.928
2016	10	%	—	1,000,000	$	4.410
2017	—		—	—	—

We utilize the following procurement guidelines for our electric segment, allowing the flexibility to hedge up to 100% of the current year’s and 80% of any future year’s expected requirements while being cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in any given month. For years beyond year four, additional factors of long term uncertainty (including with respect to required volumes and counterparty credit) are also considered.

Year	Minimum % Hedged
Current	Up to 100%
First	60%
Second	40%
Third	20%
Fourth	10%

Gas

We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of March 31, 2013, we had 0.2

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million Dths in storage on the three pipelines that serve our customers. This represents 10% of our storage capacity.

The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of March 31, 2013 (in thousands).

Season	Minimum % Hedged	Dth Hedged —  Financial	Dth Hedged —  Physical	Dth in Storage	Actual %  Hedged
Current	50%	160,000	22,246	190,358	12	%
Second	Up to 50%		—	—	—
Third	Up to 20%	—	—	—	—
Total		160,000	22,246	190,358

A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment for each of the periods ended March 31, (in thousands).

Non-Designated Hedging	Balance Sheet	Amount of Gain / (Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Classification of Gain or	Three Months Ended					Twelve Months Ended
Accounting — Gas Segment	(Loss) on Derivative	2013		2012			2013		2012
Commodity contracts	Regulatory (assets)/liabilities	$	95	$	(655	)	$	289	$	(2,475	)
Total - Gas Segment		$	95	$	(655	)	$	289	$	(2,475	)

Contingent Features

Certain of our derivative instruments contain provisions that require our senior unsecured debt to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position on March 31, 2013 is $1.9 million for which we have posted no collateral in the normal course of business. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2013, we would have been required to post $1.9 million of collateral with one of our counterparties. On March 31, 2013, we had no collateral posted with this counterparty. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Conversely, we are required to post collateral with counterparties at certain thresholds, which is typically the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent counterparty funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at March 31, 2013 and December 31, 2012. There were no margin deposit liabilities at these dates.

(in millions)	March 31, 2013		December 31, 2012
Margin deposit assets	$	3.1	$	4.2

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Offsetting of derivative assets and liabilities

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from a default under derivatives agreements by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; and (2) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master trading and netting agreement level by the counterparty.

As shown above, our asset and liability commodity contract derivatives are reported at gross on the balance sheet. Accounting Standards Codification (ASC) guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. For the periods ended March 31, 2013 and December 31, 2012, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts.

Note 5— Fair Value Measurements

The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 2 fair value measurements consist of both quoted price inputs and inputs that are derived principally from or corroborated by observable market data.

The guidance also requires that the fair value measurements of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit default spreads, we factored the impact of our own credit standing and the credit standing of our counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements.

The following fair value hierarchy table presents information about our assets measured at fair value using the market value approach on a recurring basis as of March 31, 2013 and December 31, 2012:

	Fair Value Measurements at Reporting Date Using
($ in 000’s) Description	Assets/(Liabilities) at Fair Value			Quoted Prices in  Active Markets for  Identical Liabilities (Level 1)			Significant Other  Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	March 31, 2013
Derivative assets	$	1,156		$	1,156
Derivative liabilities	$	(5,212	)	$	(5,212	)	$	—	$	—
	December 31, 2012
Derivative assets	$	287		$	287		$	—	$	—
Derivative liabilities	$	(7,222	)	$	(7,222	)	$	—	$	—

Our cash and cash equivalents approximate fair value because of the short-term nature of these instruments, and are classified as Level 1 in the fair value hierarchy. The carrying amount of our short-term debt, which is composed of Empire issued commercial paper or revolving credit

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borrowings, also approximates fair value because of their short-term nature. These instruments are classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The carrying amount of our total long-term debt exclusive of capital leases at March 31, 2013, was $687.5 million as compared to $674.8 million at March 31, 2012. The fair market value at March 31, 2013 was approximately $737.9 million as compared to approximately $726.7 million at March 31, 2012. These estimates were based on a bond pricing model, utilizing inputs classified as Level 2 in the fair value hierarchy, which include the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of March 31, 2013 or that will be realizable in the future.

Note 6— Financing

On October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due 2033 and $120.0 million of 4.32% First Mortgage Bonds due 2043. The delayed settlement is anticipated to occur on or about May 30, 2013, subject to customary closing conditions. We expect to use the proceeds from the sale of the bonds to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013 with the remaining proceeds to be used for general corporate purposes. The bonds have not been registered under the Securities Act of 1933, as amended, and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. The bonds will be issued under the EDE Mortgage. The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage.

We have an unsecured revolving credit facility of $150 million in place through January 17, 2017. The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of March 31, 2013, we are in compliance with these ratios. Our total indebtedness is 49.7% of our total capitalization as of March 31, 2013 and our EBITDA is 5.0 times our interest charges. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at March 31, 2013. However, $23.0 million was used to back up our outstanding commercial paper.

Note 7— Commitments and Contingencies

Legal Proceedings

We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has provided accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.

On May 22, 2009, a suit was filed in the Circuit Court of Platte County Missouri by several individuals and Class Representatives alleging damages to land, structures, equipment and devastation of crops due to inappropriate management of the levee system around the Iatan Generating Station, of which we are a 12% owner. The parties reached a confidential settlement in November 2012 and a consent judgment dismissing the case and giving public notice of the land

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condition was entered on January 15, 2013. The resolution of this suit did not have a material impact on our results of operations, financial position or liquidity.

A lawsuit was filed in Jasper County Circuit Court (the Court) against us by three of our residential customers, purporting to act on behalf of all Empire customers. These customers were seeking a refund of certain amounts paid for service provided by Empire between January 1, 2007, and December 13, 2007. At all times, we charged the three plaintiffs, and all of our customers, the rates approved by and on file with the MPSC from our 2006 rate case. While the precise circumstances of Empire’s 2006 rate case and the approval of Empire’s tariffs have not previously been addressed by Missouri’s appellate courts, we believe that case law supports the position that the MPSC may not re-determine rates already established and paid without depriving the utility, or a consumer if the rates were originally too low, of its property without due process.

We filed a motion asking the Court to dismiss the case on the basis that the plaintiffs had not stated a valid claim. A hearing on our motion was held April 18, 2012. The Court granted Empire’s motion to dismiss, and a judgment was issued by the Court on June 29, 2012, dismissing the case. The plaintiffs filed a Notice of Appeal on July 30, 2012. The Missouri Court of Appeals for the Southern District dismissed the case for failure to properly perfect the appeal. The plaintiffs moved to set aside the dismissal, and the Court of Appeals restored the case to its active docket. The parties filed briefs and the Court of Appeals has taken the case under advisement.

Coal, Natural Gas and Transportation Contracts

The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of March 31, 2013 (in millions).

	Firm physical gas and transportation contracts		Coal and coal  transportation contracts
April 1, 2013 through December 31, 2013	$	24.5	$	16.8
January 1, 2014 through December 31, 2015	29.9		32.1
January 1, 2016 through December 31, 2017	22.2		22.7
January 1, 2018 and beyond	8.3		22.7

In addition to the above, we have signed an agreement with Southern Star Central Pipeline, Inc. to purchase one million Dths of firm gas storage service capacity for our electric business for a period of five years, expiring April 2016. The reservation charge for this storage capacity is approximately $1.1 million annually.

We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used at our plants, the gas would be liquidated at market price. The firm physical gas and transportation commitments are detailed in the table above.

We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts as of March 31, 2013, are detailed in the table above.

Purchased Power

We currently supplement our on-system generating capacity with purchases of capacity and energy from other entities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.

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The Plum Point Energy Station (Plum Point) is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the unit’s capacity. We also have a long-term (30 year) agreement for the purchase of capacity from Plum Point. We began receiving purchased power under this agreement on September 1, 2010. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. At this time it is not our intention to exercise this option.  Rather, we intend to continue to meet our demand and capacity requirements with the continuation of this long-term purchased power agreement. We will, however, continue to analyze this option during our 2013 IRP process. Commitments under this agreement are approximately $304.3 million through August 31, 2039, the end date of the agreement.

We have a 20-year purchased power agreement, which began on December 15, 2008, with Cloud County Windfarm, LLC, owned by EDP Renewables North America LLC (formerly Horizon Wind Energy), Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost. We also have a 20-year contract, which began on December 15, 2005, with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $16.9 million based on a 20-year average cost. Although these agreements are considered operating leases under Generally Accepted Accounting Principles (GAAP), payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in our operating lease obligations. We do not own any portion of these windfarms.

New Construction

On January 16, 2012, we signed a contract with a third party vendor to complete environmental retrofits at our Asbury plant. The retrofits will include the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This equipment will enable us to comply with the recently finalized Mercury and Air Toxics Standard (MATS). See “Environmental Matters” below for more information and for project costs.

Leases

We have purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC, which are considered operating leases for GAAP purposes. Details of these agreements are disclosed in the Purchased Power section of this note.

We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for one office facility related to our gas segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal delivery for our ownership and purchased power agreement shares of the Plum Point generating facility.

Environmental Matters

We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and hazardous and other wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as remediation of contaminated sites and other environmental matters. We believe that our operations are in material compliance with present environmental laws and regulations. Environmental requirements have changed frequently and become more stringent over time. We expect this trend to continue. While we are not in a position to accurately estimate compliance costs for any new requirements, we expect any such costs to be material, although recoverable in rates.

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Electric Segment

Air

The Federal Clean Air Act (CAA) and comparable state laws regulate air emissions from stationary sources such as electric power plants through permitting and/or emission control and related requirements. These requirements include maximum emission limits on our facilities for sulfur dioxide (SO2), particulate matter, nitrogen oxides (NOx) and mercury. In the future they are also likely to include limits on other hazardous pollutants (HAPs) and so-called greenhouse gases (GHG) such as carbon dioxide (CO2) and methane.

Permits

Under the CAA we have obtained, and renewed as necessary, site operating permits, which are valid for five years, for each of our plants.

Compliance Plan

In order to comply with forthcoming environmental regulations, Empire is taking actions to implement its compliance plan and strategy (Compliance Plan).  While the Cross State Air Pollution Rule (CSAPR — formerly the Clean Air Transport Rule, or CATR) that was set to take effect on January 1, 2012 was stayed in late December 2011 then vacated in August 2012 by the District of Columbia Circuit Court of Appeals, the Mercury Air Toxics Standard (MATS) was signed by the Environmental Protection Agency (EPA) Administrator on December 16, 2011 and became effective on April 16, 2012. MATS requires compliance by April 2015 (with flexibility for extensions for reliability reasons). Our Compliance Plan largely follows the preferred plan presented in our most recent Integrated Resource Plan. As described above under New Construction, we have begun the installation of a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant. The addition of this air quality control equipment is expected to be completed by early 2015 at a cost ranging from $112.0 million to $130.0 million, excluding AFUDC. Construction costs through March 31, 2013 were $18.7 million for 2013 and $48.9 million for the project to date, excluding AFUDC. The addition of this air quality control equipment will require the retirement of Asbury Unit 2, an 18 megawatt steam turbine that is currently used for peaking purposes.

In September 2012, we completed the transition of our Riverton Units 7 and 8 from operation on coal to operating completely on natural gas. Riverton Units 7 and 8, along with Riverton Unit 9, a small combustion turbine that requires steam from Unit 7 or 8 for start-up, will be retired upon the conversion of Riverton Unit 12, a simple cycle combustion turbine, to a combined cycle unit. This conversion is currently scheduled to be completed in 2016.

SO2 Emissions

The CAA regulates the amount of SO2 an affected unit can emit. Currently SO2 emissions are regulated by the Title IV Acid Rain Program and the Clean Air Interstate Rule (CAIR). On January 1, 2012, CAIR was to have been replaced by the Cross-State Air Pollution Rule (CSAPR). But, as discussed above, CSAPR was subsequently vacated, and CAIR will remain in effect until the EPA develops a valid replacement.

On October 5, 2012, the Department of Justice, on behalf of the EPA, requested that the Court of Appeals grant a request for a re-hearing of CSAPR. On January 24, 2013, the request was denied by the Court of Appeals and on March 29, 2013, the EPA petitioned the United States Supreme Court to review the D.C. Circuit Court’s decision. In the meantime, both the Title IV Acid Rain Program and CAIR will remain in effect.

The Mercury Air Toxics Standards (MATS), discussed further below, was signed on December 16, 2011, and will affect SO2 emission rates at our facilities. In addition, the compliance date for the revised SO2 National Ambient Air Quality Standards (NAAQS) is August of 2017; this will also affect SO2 emissions at our facilities. The SO2 NAAQS is discussed in more detail below.

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Title IV Acid Rain Program:

Under the Title IV Acid Rain Program, each existing affected unit has been allocated a specific number of emission allowances by the U.S. Environmental Protection Agency (EPA).  Each allowance entitles the holder to emit one ton of SO2. Covered utilities, such as Empire, must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. Allowances in excess of the annual emissions are banked for future use. In 2012, our SO2 emissions exceeded the annual allocations. This deficit was covered by our banked allowances. We estimate our Title IV Acid Rain Program SO2 allowance bank plus annual allocations will be more than our projected emissions through 2016. Long-term compliance with this program will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. We expect the cost of compliance to be fully recoverable in our rates.

CAIR:

In 2005, the EPA promulgated CAIR under the CAA. CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of SO2 and/or NOx in 28 eastern states and the District of Columbia, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located. Kansas was not included in CAIR and our Riverton Plant was not affected. Arkansas, where our Plum Point Plant is located, was included for ozone season NOx but not for SO2.

In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR and remanded it back to EPA for further consideration, but also stayed its vacatur. As a result, CAIR became effective for NOx on January 1, 2009 and for SO2 on January 1, 2010 and required covered states to develop State Implementation Plans (SIPs) to comply with specific SO2 state-wide annual budgets.

SO2 allowance allocations under the Title IV Acid Rain Program are used for compliance in the CAIR SO2 Program. Beginning in 2010, SO2 allowances were utilized at a 2:1 ratio for our Missouri units. As a result, based on current SO2 allowance usage projections, we expected to have sufficient allowances to take us through 2016.

In order to meet CAIR requirements for SO2 and NOx emissions (NOx is discussed below in more detail) and as a requirement for the air permit for Iatan 2, a Selective Catalytic Reduction system (SCR), a Flue-Gas Desulfurization (FGD) scrubber system and baghouse were installed at our jointly-owned Iatan 1 plant and a SCR was placed in service at our Asbury plant in 2008. Our jointly-owned Iatan 2 and Plum Point plants were originally constructed with the above technology.

CSAPR- formerly the Clean Air Transport Rule:

On July 6, 2010, the EPA published a proposed CAIR replacement rule entitled the Clean Air Transport Rule (CATR). As proposed and supplemented, the CATR included Missouri and Kansas under both the annual and ozone season for NOx as well as the SO2 program while Arkansas remained in the ozone season NOx program only. The final CATR was released on July 7, 2011 under the name of the CSAPR, and was set to become effective January 1, 2012. However, as mentioned above, the District of Columbia Circuit Court of Appeals vacated CSAPR on August 21, 2012, and the EPA has subsequently petitioned the Supreme Court to review the D.C. Circuit Court’s decision. The CAIR will be in effect until a valid replacement is developed by the EPA.

When it was published, the final CSAPR required a 73% reduction in SO2 from 2005 levels by 2014. The SO2 allowances allocated under the EPA’s Title IV Acid Rain Program could not be used for compliance with CSAPR but would continue to be used for compliance with the Title IV Acid Rain Program. Therefore, new SO2 allowances would be allocated under CSAPR and retired at one allowance per ton of SO2 emissions emitted. Based on current projections, we would receive more SO2 allowances than would be emitted. Long-term compliance with this Rule will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. We anticipate compliance costs associated with CAIR or its subsequent replacement to be recoverable in our rates.

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Mercury Air Toxics Standard (MATS):

The MATS standard was fully implemented and effective as of April 16, 2012, thus requiring compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The MATS regulation does not include allowance mechanisms. Rather, it establishes alternative standards for certain pollutants, including SO2 (as a surrogate for hydrogen chloride (HCI)), which must be met to show compliance with hazardous air pollutant limits (see additional discussion in the MATS section below).

SO2 National Ambient Air Quality Standard (NAAQS):

In June 2010, the EPA finalized a new 1-hour SO2 NAAQS which, for areas with no ambient SO2 monitor, originally required modeling to determine attainment and non-attainment areas within each state. In April 2012, the EPA announced that it is reconsidering this approach. The modeling of emission sources was to have been completed by June 2013 with compliance with the SO2 NAAQS required by August 2017. Because the EPA is reconsidering the compliance determination approach for areas without ambient SO2 monitors, the compliance time-frame may be pushed back. Draft guidance for 1-hour SO2 NAAQS has been published by the EPA to assist states as they prepare their SIP submissions. The EPA is also planning a rulemaking to address some of the 1-hour SO2 NAAQS implementation program elements. It is likely coal-fired generating units will need scrubbers to be capable of meeting the new 1-hour SO2 NAAQS. In addition, units will be required to include SO2 emissions limits in their Title V permits or execute consent decrees to assure attainment and future compliance.

NOx Emissions

The CAA regulates the amount of NOx an affected unit can emit. As currently operated, each of our affected units is in compliance with the applicable NOx limits. Currently, revised NOx emissions are limited by the CAIR as a result of the vacated CSPAR rule and by ozone NAAQS rules (discussed below) which were established in 1997 and in 2008.

CAIR:

The CAIR required covered states to develop SIPs to comply with specific annual NOx state-wide allowance allocation budgets. Based on existing SIPs, we had excess NOx allowances during 2011 which were banked for future use and will be sufficient for compliance at least through the end of 2016. The CAIR NOx program also was to have been replaced by the CSAPR program January 1, 2012 but because the Court vacated CSAPR, CAIR will remain in effect until the EPA develops a valid replacement.

CSAPR:

As published, the CSAPR would have required a 54% reduction in NOx from 2005 levels by 2014. The NOx annual and ozone season allowances that were allocated and banked under CAIR could not be used for compliance under CSAPR. New allowances would have been issued under CSAPR. However, as discussed above, CSPAR was vacated by the District of Columbia Circuit Court of Appeals on August 21, 2012 and the EPA has subsequently petitioned the Supreme Court to review the D.C. Circuit Court’s decision.

Ozone NAAQS:

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. On January 6, 2010, to protect public health, the EPA proposed to lower the primary NAAQS for ozone to a range between 60 and 70 ppb and to set a separate secondary NAAQS for ozone to protect sensitive vegetation and ecosystems.

On September 2, 2011, President Obama ordered the EPA to withdraw proposed air quality standards lowering the 2008 ozone standard pending the CAA 2013 scheduled reconsideration of the

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ozone NAAQS (the normal 5 year reconsideration period). States will move forward with area designations based on the 2008 75 ppb standard using 2008-2010 quality assured monitoring data. Our service territory will be designated as attainment, meaning it will be in compliance with the standard. In the interim, the 1997 ozone NAAQS will remain in effect.

PM NAAQS:

Particulate matter (PM) is the term for particles found in the air which comes from a variety of sources. On January 15, 2013, the EPA finalized the PM 2.5 primary annual standard at 12 ug/m3 (micrograms per cubic meter of air). States are required to meet the primary standard in 2020.

The standard should have no impact on our existing generating fleet because the PM 2.5 ambient monitor results are below the required level. However, the proposed standards could impact future major modifications/construction projects that require a Prevention of Significant Deterioration (PSD) permit.

Mercury Air Toxics Standard (MATS)

In 2005, the EPA issued the Clean Air Mercury Rule (CAMR) under the CAA. It set limits on mercury emissions by power plants and created a market-based cap and trade system expected to reduce nationwide mercury emissions in two phases. New mercury emission limits for Phase 1 were to go into effect January 1, 2010. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia vacated CAMR. This decision was appealed to the U.S. Supreme Court which denied the appeal on February 23, 2009.

The EPA issued Information Collection Requests (ICR) for determining the National Emission Standards for Hazardous Air Pollutants (NESHAP), including mercury, for coal and oil-fired electric steam generating units on December 24, 2009. The ICRs included our Iatan, Asbury and Riverton plants. All responses to the ICRs were submitted as required. The EPA ICRs were intended for use in developing regulations under Section 112(r) of the CAA maximum achievable emission standards for the control of the emission of hazardous air pollutants (HAPs), including mercury. The EPA proposed the first ever national mercury and air toxics standards (MATS) in March 2011, which became effective April 16, 2012. MATS establishes numerical emission limits to reduce emissions of heavy metals, including mercury (Hg), arsenic, chromium, and nickel, and acid gases, including HCl and hydrogen fluoride (HF). For all existing and new coal-fired electric utility steam generating units (EGUs), the proposed standard will be phased in over three years, and allows states the ability to give facilities a fourth year to comply. On March 28, 2013, the EPA finalized updates to certain emission limits for new power plants under the MATS. The new standards affect only new coal and oil-fired power plants that will be built in the future. The update does not change the final emission limits or other requirements for existing power plants.

The MATS regulation of HAPs in combination with CSAPR is the driving regulation behind our Compliance Plan and its implementation schedule.  We expect compliance costs to be recoverable in our rates.

Greenhouse Gases

Our coal and gas plants, vehicles and other facilities, including EDG (our gas segment), emit CO2 and/or other Greenhouse Gases (GHGs) which are measured in Carbon Dioxide Equivalents (CO2e).

On September 22, 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases Rule under the CAA which requires power generating and certain other facilities that equal or exceed an emission threshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually commencing in September 2011. EDE and EDG’s GHG emissions for 2011 and 2012 have been reported as required to the EPA.

On December 7, 2009, responding to a 2007 U.S. Supreme Court decision that determined that GHGs constitute “air pollutants” under the CAA, the EPA issued its final finding that GHGs threaten both the public health and the public welfare. This “endangerment” finding did not itself trigger any EPA regulations, but was a necessary predicate for the EPA to proceed with regulations to

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control GHGs. Since that time, a series of rules including the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule) have been issued by the EPA. Several parties have filed petitions with the EPA and lawsuits have been filed challenging these rules. On June 26, 2012, the D.C. Circuit Court issued its opinion in the principal litigation of the EPA GHG rules (Endangerment, the Tailoring Rule, GHG emission standards for light-duty vehicles, and the EPA’s rule on reconsideration of the PSD Interpretive Memorandum). The three-judge panel upheld the EPA’s interpretation of the Clean Air Act provisions as unambiguously correct. This opinion solidifies the EPA’s position that the CAA requires PSD and Title V permits for major emitters of greenhouse gases, such as Empire. Our ongoing projects are currently being evaluated for the projected increase or decrease of CO2e emissions as required by the Tailoring Rule.

As the result of an agreement to settle litigation pending in the U.S. Court of Appeals, on March 27, 2012, the EPA proposed a Carbon Pollution Standard for new power plants. This action is designed to limit the amount of carbon emitted by electric utility generating units. The New Source Performance Standard would require all new power plants to meet a CO2 emissions limit of 1,000 pounds per megawatt hour. This is equal to a coal-fired power plant capturing 50% or more of its emissions. The rule does offer some flexibility but would still require an average of 1,000 pounds per megawatt hour over a 30-year period. It is expected that most new natural gas-fired combined cycles will meet the new standard. The proposed rule would apply only to new fossil-fuel-fired electric utility generating units. The proposal would not apply to existing units including modifications such as those required to meet other air pollution standards which are currently being undertaken at our Asbury facility. Comments for the proposed regulation are currently under consideration by the EPA, and Empire will determine the impact on the Riverton Unit 12 conversion after the final rule is released. Final standards are expected in 2013. At this time, the regulation does not propose a standard of performance for modifications, and we do not expect the Riverton 12 combined cycle permitting to be affected. Proposed EPA NSPS regulations (through state guidelines) for existing plants are expected in late 2013.

A variety of proposals have been and are likely to continue to be considered by Congress to reduce GHGs. Proposals are also being considered in the House and Senate that would delay, limit or eliminate EPA’s authority to regulate GHGs. At this time, it is not possible to predict what legislation, if any, will ultimately emerge from Congress regarding control of GHGs.

Certain states have taken steps to develop cap and trade programs and/or other regulatory systems which may be more stringent than federal requirements. For example, Kansas is a participating member of the Midwestern Greenhouse Gas Reduction Accord (MGGRA), one purpose of which is to develop a market-based cap and trade mechanism to reduce GHG emissions. The MGGRA has announced, however, that it will not issue a CO2e regulatory system pending federal legislative developments. Missouri is not a participant in the MGGRA.

The ultimate cost of any GHG regulations cannot be determined at this time. However, we expect the cost of complying with any such regulations to be recoverable in our rates.

Water Discharges

We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Clean Water Act (CWA). Our plants are in material compliance with applicable regulations and have received necessary discharge permits.

The Riverton Units 7 and 8 and Iatan Unit 1, which utilize once-through cooling water, were affected by regulations for Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) Phase II. The regulations became final on February 16, 2004. In accordance with these regulations, we submitted sampling and summary reports to the Kansas Department of Health and Environment (KDHE) which indicate that the effect of the cooling water intake structure on Empire Lake’s aquatic life is insignificant. KCP&L, who operates Iatan Unit 1, submitted the appropriate sampling and summary reports to the Missouri Department of Natural Resources (MDNR).

In 2007 the United States Court of Appeals for the Second Circuit remanded key sections of these CWA regulations to the EPA. As a result, the EPA suspended the regulations and revised and signed a pre-publication proposed regulation on March 28, 2011. The EPA has secured an additional

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year to finalize the standards for cooling water intake structures under a modified settlement agreement. The EPA is obligated to finalize the rule by July 27, 2013. We will not know the full impact of these rules until they are finalized. If adopted in their present form, we expect regulations of Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) to have a limited impact at Riverton.  The retirement of units 7 and 8 are scheduled in 2016. A new intake structure design and cooling tower will be constructed as part of the Unit 12 conversion at Riverton. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit. Our new Iatan Unit 2 and Plum Point Unit 1 are covered by the proposed regulation but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally impacted by the final rule.

Surface Impoundments

We own and maintain coal ash impoundments located at our Riverton and Asbury Power Plants. Additionally, we own a 12% interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a coal ash impoundment at Plum Point. On April 19, 2013, the EPA signed a notice of proposed rulemaking to revise its wastewater effluent limitation guidelines and standards under the CWA for coal-fired power plants. The proposal calls for updates to operating permits beginning in July 2017. Once the new guidelines are issued, the EPA and states would incorporate the new standards into wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs that might result from any new standards. All of our coal ash impoundments are compliant with existing state and federal regulations.

On June 21, 2010, the EPA proposed a new regulation pursuant to the Federal Resource Conservation and Recovery Act (RCRA) governing the management and storage of Coal Combustion Residuals (CCR). In the proposal, the EPA presents two options: (1) regulation of CCR under RCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRA subtitle D as a non-hazardous waste. The public comment period closed in November 2010. It is anticipated that the final regulation will be published in 2014. We expect compliance with either option as proposed to result in the need to construct a new landfill and the conversion of existing ash handling from a wet to a dry system(s) at a potential cost of up to $15 million at our Asbury and Riverton Power Plants. This preliminary estimate will likely change based on the final CCR rule and its requirements. We expect resulting costs to be recoverable in our rates.

On September 23, 2010 and on November 4, 2010 EPA consultants conducted on-site inspections of our Riverton and Asbury coal ash impoundments, respectively. The consultants performed a visual inspection of the impoundments to assess the structural integrity of the berms surrounding the impoundments, requested documentation related to construction of the impoundments, and reviewed recently completed engineering evaluations of the impoundments and their structural integrity. In response to the inspection comments, the recommended geotechnical studies have been completed and new flow monitoring devices and settlement monuments at both coal ash impoundments have been installed.  Final geotechnical engineer report documents for both site impoundments have been received.

As a result of the transition from coal to natural gas, initial planning for the closure of the Riverton impoundment is in progress in coordination with the KDHE Bureau of Waste Management. We expect to close it in 2014. The final design for additional recommendations that will improve safety for slope stability at the Asbury impoundment is under review. The site assessment project has complied with all corrective measures and recommendations made by the EPA in the initial site assessment reports. We have received approval by the MDNR for the permitting of a new utility waste landfill adjacent to the Asbury plant.

Renewable Energy

As previously discussed, we have purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas. We do not own any portion of either windfarm.  More than 15% of the energy we put into the

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grid comes from these long-term Purchased Power Agreements (PPAs). Through these PPAs, we generate about 900,000 renewable energy certificates (RECs) each year. A REC represents one megawatt-hour of renewable energy that has been delivered into the bulk power grid and “unbundles” the renewable attributes from the associated energy. This unbundling is important because it cannot be determined where the renewable energy is ultimately delivered once it enters the bulk power grid. As a result, RECs provide an avenue for renewable energy tracking and compliance purposes.

Missouri regulations currently require us and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase RECs, at the rate of at least 2% of retail sales in 2012, increasing to at least 15% by 2021. We are currently in compliance with this regulatory requirement. The regulations require that 2% of the renewable energy source must be solar; however, we believe we are exempted from the solar requirement. A challenge to our exemption, brought by two of our customers and Power Source Solar, Inc., was dismissed on May 31, 2011 by the Missouri Western District Court of Appeals. The plaintiffs filed in the Missouri Supreme Court for transfer of the case from the Missouri Western District to the Missouri Supreme Court. The transfer was denied. On January 30, 2013, a complaint was filed with the MPSC by Renew Missouri and others regarding several points of our 2011 RES Compliance Report and the 2012-2014 Compliance Plan. The complaint is currently under consideration by the MPSC.

Renewable energy standard compliance rules were published by the MPSC on July 7, 2010.  Missouri investor-owned utilities and others initiated litigation to challenge these rules. On June 30, 2011, a Cole County Circuit Court judge ruled that portions of the MPSC rules were unlawful and unreasonable, in conflict with Missouri statute and in violation of the Missouri Constitution. Subsequent to that decision, a portion of the appeal was dropped and the entire order was stayed.  On December 27, 2011 the judge issued another order identical to the one that was stayed except that the rulings with regard to the constitutionality issue had been omitted. The MPSC appealed this decision and in November of 2012 the court dismissed lawsuits brought against the RES and affirmed the MPSC rules that were finalized in July 2010. Kansas established a renewable portfolio standard (RPS), effective November 19, 2010. It requires 10% of our Kansas retail customer peak capacity requirements to be sourced from renewables in 2012, increasing to 15% by 2016, and 20% by 2020. In addition, there are several proposals currently before the U.S. Congress to adopt a nationwide RPS.

We have been selling the majority of our RECs and plan to continue to sell all or a portion of them moving forward. As a result of these REC sales, we cannot claim the underlying energy is renewable. Once a REC has been claimed or retired, it cannot be used for any other purpose. At the end of 2012, sufficient RECs, including hydro, were retired to comply with the Missouri and Kansas requirements through the end of November 2012. Additional RECs were retired in January of 2013 to complete the process for 2012. In the future, we will continue to retain a sufficient amount of RECs to meet any current or future requirements.

Gas Segment

The acquisition of Missouri Gas in June 2006 involved the property transfer of two former manufactured gas plant (FMGP) sites previously owned by Aquila, Inc. and its predecessors. Site #1 in Chillicothe, Missouri is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. No remediation of this site is expected to be required in the near term.  We have received a letter stating no further action is required from the MDNR with respect to Site #2 in Marshall, Missouri. We have incurred $0.2 million in remediation costs and estimate further remediation costs at these two FMGP sites to be minimal.

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Note 8 — Retirement Benefits

Net periodic benefit cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, is comprised of the following components and is shown for our noncontributory defined benefit pension plan, our supplemental retirement program (SERP) and other postretirement benefits (OPEB) (in thousands):

	Three months ended March 31,
	Pension						SERP						OPEB
	2013			2012			2013			2012			2013			2012
Service cost	$	1,868		$	1,628		$	15		$	7		$	755		$	565
Interest cost	2,509			2,551			63			56			992			1,032
Expected return on plan assets	(3,125		)	(3,076		)	—			—			(1,099		)	(1,041		)
Amortization of prior service cost (1)	133			133			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	2,590			1,950			104			76			649			468
Net periodic benefit cost	$	3,975		$	3,186		$	180		$	137		$	1,044		$	771

	Twelve months ended March 31,
	Pension						SERP						OPEB
	2013			2012			2013			2012			2013			2012
Service cost	$	6,500		$	5,830		$	59		$	81		$	2,591		$	2,205
Interest cost	10,215			10,366			270			198			3,996			4,286
Expected return on plan assets	(12,358		)	(11,534		)	—			—			(4,193		)	(4,148		)
Amortization of prior service cost (1)	532			532			(8		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	8,576			6,091			416			213			1,844			1,729
Net periodic benefit cost	$	13,465		$	11,285		$	737		$	484		$	3,227		$	3,061

(1) Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.

In accordance with our regulatory agreements, our pension funding policy is to make contributions that are at least equal to the greater of either the minimum funding requirements of ERISA or the accrued cost of the plan. We expect to make pension contributions of approximately $15.9 million during 2013. The actual minimum funding requirements will be determined based on the results of the actuarial valuations. Our OPEB funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits.

Note 9 — Stock-Based Awards and Programs

Our performance-based restricted stock awards, stock options and their related dividend equivalents and time-vested restricted stock awards are valued as liability awards, in accordance with fair value guidelines. We allow employees to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the awards are classified as liability instruments under the ASC guidance on share based payment. Awards treated as liability instruments must be revalued each period until settled, and cost is accrued over the requisite service period and adjusted to fair value at each reporting period until settlement or expiration of the award.

We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended March 31 (in thousands):

	Three Months Ended				Twelve Months Ended
	2013		2012		2013		2012
Compensation expense	$	1,291	$	822	$	2,332	$	1,846
Tax benefit recognized	476		298		827		642

Activity for our various stock plans for the three months ended March 31, 2013, is summarized below:

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Performance-Based Restricted Stock Awards

Performance-based restricted stock awards are granted to qualified individuals consisting of the right to receive a number of shares of common stock at the end of the restricted period assuming performance criteria are met. The fair value of the outstanding restricted stock awards was estimated using a Monte Carlo option valuation model. The assumptions used in the model for each grant year are noted in the following table:

	Fair Value of Grants Outstanding at March 31,
	2013	2012
Risk-free interest rate	0.12% to 0.32%	0.16% to 0.45%
Expected volatility of Empire stock	20.5%	21.5%
Expected volatility of peer group stock	12.1% to 30.8%	13.5% to 51.9%
Expected dividend yield on Empire stock	4.5%	4.9%
Expected forfeiture rates	3%	3%
Plan cycle	3 years	3 years
Fair value percentage	10.0% to 99.0%	41.0% to 104.0%
Weighted average fair value per share	$17.06	$13.63

Non-vested performance-based restricted stock awards (based on target number) as of March 31, 2013 and 2012 and changes during the three months ended March 31, 2013 and 2012 were as follows:

	2013				2012
	Number of shares		Weighted Average  Grant Date Price		Number of shares		Weighted Average Grant Date Price
Outstanding at January 1,	33,900		$	20.25	37,400		$	19.28
Granted	26,300		$	21.36	10,000		$	20.97
Awarded	(4,460	)	$	18.36	(7,823	)	$	18.12
Not Awarded	(8,540	)	$	18.36	(5,677	)	$	18.12
Nonvested at March 31,	47,200		$	21.39	33,900		$	20.25

At March 31, 2013, there was $0.6 million of total unrecognized compensation cost related to estimated outstanding awards. This cost will be recognized over the outstanding years remaining in the vesting period.

Time-Vested Restricted Stock Awards

Beginning in 2011, we began granting, to qualified individuals, time-vested restricted stock awards that vest after a three-year period, in lieu of stock options. No dividend rights accumulate during the vesting period. Time-vested restricted stock is valued at an amount equal to the fair market value of our common stock on the date of grant. If employment terminates during the vesting period because of death, retirement, or disability, the participant is entitled to a pro-rata portion of the time-vested restricted stock awards such participant would otherwise have earned, which is distributed six months following the date of termination, with the remainder of the award forfeited. If employment is terminated during the vesting period for reasons other than those listed above, the time-vested restricted stock awards will be forfeited on the date of the termination, unless the Board of Directors Compensation Committee determines, in its sole discretion, that the participant is entitled to a pro-rata portion of the award.

The fair value measurements for each grant year are noted in the following table:

	Fair Value of Grants Outstanding at March 31
	2013	2012
Total unrecognized compensation cost (in millions)	$0.3	Less than $0.1
Recognition period	1-3 years	1.75 years
Fair value	$19.63	$17.63

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No shares of time-vested restricted stock were granted in 2012 as a result of the limitation on incentive compensation in place in 2011. A summary of time vested restricted stock activity under the plan for 2012 and 2013 is presented in the table below:

	March 31, 2013			March 31, 2012
		Weighted				Weighted
	Number of	Average Fair		Number of		Average Fair
	shares	Market Value		shares		Market Value
Outstanding at January 1,	3,300	$	20.38	3,433		$	21.84
Granted	21,600	21.36		—		—
Vested	—	—		—		—
Distributed				(133	)	20.13
Forfeited	—	—		—		—
Vested but not distributed	—	—		—		—
Outstanding at end of period	24,900	$	22.40	3,300		$	20.38

All time-vested restricted stock awards are classified as liability instruments, which must be revalued each period until settled. The cost of the awards is generally recognized over the requisite (explicit) service period.

Stock Options

Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. The fair value of the outstanding options was estimated as of March 31, 2013 and 2012, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

	Fair Value of Grants Outstanding at March 31,
	2013	2012
Risk-free interest rate	0.11% to 0.28%	0.17% to 0.83%
Expected dividend yield	4.5%	4.9%
Expected volatility	24.0%	25.0%
Expected life in months	78	78
Market value	$22.40	$20.35
Weighted average fair value per option	$1.64	$1.56

A summary of option activity under the plan during the quarters ended March 31, 2013 and March 31, 2012 is presented below:

	2013			2012
		Weighted			Weighted
		Average			Average
	Options	Exercise Price		Options	Exercise Price
Outstanding at January 1,	163,300	$	23.15	190,300	$	21.56
Granted	—	—		—	—
Exercised	34,800	$	18.36	27,000	$	18.12
Outstanding at March 31,	128,500	$	23.15	163,300	$	22.13
Exercisable at March 31,	128,500	$	23.15	128,500	$	23.15

The intrinsic value of the unexercised options is the difference between Empire’s closing stock price on the last day of the quarter and the exercise price multiplied by the number of in the money options had all option holders exercised their option on the last day of the quarter. The intrinsic value is zero if such closing price is less than the exercise price. The table below shows the aggregate intrinsic values at March 31, 2013 and 2012:

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	2013	2012
Aggregate intrinsic value (in millions)	Less than $0.1	Less than $0.1
Weighted-average remaining contractual life of outstanding options	2.8 years	3.9 years
Range of exercise prices	$21.79 to $23.81	$18.36 to $23.81
Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan	$0.0	Less than $0.1
Recognition period		Less than 1 year

Note 10 - Regulated Operating Expense

The following table sets forth the major components comprising “regulated operating expenses” under “Operating Revenue Deductions” on our consolidated statements of income (in thousands) for all periods presented ended March 31:

	Three Months  Ended		Three Months  Ended		Twelve Months Ended		Twelve Months Ended
	2013		2012		2013		2012
Electric transmission and distribution expense	$	5,028	$	4,108	$	18,003	$	15,647
Natural gas transmission and distribution expense	546		652		2,337		2,476
Power operation expense (other than fuel)	3,792		3,794		15,634		14,394
Customer accounts and assistance expense	2,579		2,434		10,356		10,108
Employee pension expense (1)	2,643		2,536		10,287		9,496
Employee healthcare plan (1)	2,786		2,238		10,374		8,056
General office supplies and expense	3,429		2,752		11,453		10,011
Administrative and general expense	4,315		4,219		15,187		14,868
Allowance for uncollectible accounts	746		593		3,191		3,935
Regulatory reversal of gain on sale of assets	1,236		—		1,236		—
Miscellaneous expense	37		22		102		84
Total	$	27,137	$	23,348	$	98,160	$	89,075

(1) Does not include capitalized portion of costs, but reflects the GAAP expensed cost plus or minus costs deferred to and amortized from a regulatory asset and/or a regulatory liability for Missouri, Kansas and Oklahoma jurisdictions.

Note 11— Segment Information

We operate our business as three segments:  electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The other segment consists of our fiber optics business.

The tables below present statement of income information, balance sheet information and capital expenditures of our business segments.

	For the quarter ended March 31,
	2013
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	128,762	$	20,493	$	2,033	$	(148	)	$	151,140
Depreciation and amortization	14,682		924		494		—			16,100
Federal and state income taxes	5,995		1,206		281		—			7,482
Operating income	18,515		2,895		448		—			21,858
Interest income	495		72		5		(64		)	508
Interest expense	9,337		977		—		(64		)	10,250
Income from AFUDC (debt and equity)	830		1		—		—			831
Net income	10,223		1,950		457		—			12,630
Capital Expenditures	$	40,221	$	733	$	440	$	—		$	41,394

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	For the quarter ended March 31,
	2012
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	119,726	$	15,683	$	1,883	$	(148	)	$	137,144
Depreciation and amortization	13,569		919		447		—			14,935
Federal and state income taxes	5,187		697		315		—			6,199
Operating income	18,243		2,054		513		—			20,810
Interest income	170		72		—		(63		)	179
Interest expense	10,027		977		—		(63		)	10,941
Income from AFUDC (debt and equity)	98		—		—		—			98
Net income	8,173		1,119		512		—			9,804
Capital Expenditures	$	34,079	$	725	$	944	$	—		$	35,748

	For the twelve months ended March 31,
	2013
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	519,690	$	44,659	$	7,337	$	(592	)	$	571,094
Depreciation and amortization	56,424		3,603		1,585		—			61,612
Federal and state income taxes	33,074		1,298		1,069		—			35,441
Operating income	89,717		5,845		1,707		—			97,269
Interest income	1,270		323		12		(305		)	1,300
Interest expense	37,175		3,906		—		(305		)	40,776
Income from AFUDC (debt and equity)	2,651		10		—		—			2,661
Net income	54,680		2,087		1,739		—			58,506
Capital Expenditures	$	147,220	$	3,579	$	2,096	$	—		$	152,895

	For the twelve months ended March 31,
	2012
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	515,641	$	41,124	$	7,113	$	(592	)	$	563,286
Depreciation and amortization	55,778		3,539		1,821		—			61,138
Federal and state income taxes	31,197		991		1,064		—			33,252
Operating income	88,557		5,374		1,966		—			95,897
Interest income	702		260		—		(250		)	712
Interest expense	39,086		3,910		5		(250		)	42,751
Income from AFUDC (debt and equity)	583		3		—		—			586
Net Income	49,542		1,582		1,730		—			52,854
Capital Expenditures	$	110,728	$	4,507	$	4,133	$	—		$	119,368

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As of March 31, 2013

($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,046,653	$	153,911	$	29,090	$	(93,881	)	$	2,135,773

(1) Includes goodwill of $39,492.

As of December 31, 2012

($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,034,399	$	148,814	$	28,871	$	(85,715	)	$	2,126,369

(1) Includes goodwill of $39,492.

Note 12— Income Taxes

The following table shows the changes in our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended March 31,:

	Three Months Ended						Twelve Months Ended
	2013			2012			2013			2012
Consolidated provision for income taxes	$	7.5		$	6.2		$	35.4		$	33.3
Consolidated effective federal and state income tax rates	37.2		%	38.7		%	37.7		%	38.6		%

The effective income tax rate for the three and twelve month periods ended March 31, 2013 is lower than comparable periods in 2012 primarily due to higher equity AFUDC income in 2013 compared with 2012.

We do not have any unrecognized tax benefits as of March 31, 2013. We did not recognize any significant interest or penalties in any of the periods presented. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months.

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXECUTIVE SUMMARY

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE) is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary. It provides natural gas distribution to customers in 48 communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business.

During the twelve months ended March 31, 2013, our gross operating revenues were derived as follows:

Electric segment sales*	91.0	%
Gas segment sales	7.8
Other segment sales	1.2

*Sales from our electric segment include 0.3% from the sale of water.

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Earnings

During the first quarter of 2013, basic and diluted earnings per weighted average share of common stock were $0.30 on net income of $12.6 million, as compared to $0.23 on net income of $9.8 million in the first quarter of 2012. For the twelve months ended March 31, 2013, basic and diluted earnings per weighted average share of common stock were $1.38 on net income of $58.5 million, as compared to $1.26 on net income of $52.9 million for the twelve months ended March 31, 2012.

Weather was the primary positive driver for the quarter, with the first quarter of 2013 being considerably colder than the first quarter of 2012, when the warmest temperatures on record were recorded. This positively impacted both electric and gas gross margins for the three months ended March 31, 2013. We define electric gross margins as electric revenues less fuel and purchased power costs. We define gas gross margins as gas operating revenues less cost of gas in rates.

Negative drivers for the first quarter of 2013 included increased regulated operating expense, depreciation and amortization expense and a regulatory write off of approximately $3.6 million discussed below.

Although the twelve month ended 2013 and 2012 periods were both impacted favorably by above average warm weather during the summer cooling months, the colder 2013 first quarter weather resulted in a small favorable margin impact in the 2013 period. Improving customer counts in the twelve month ended 2013 period also had a positive impact on electric gross margin, as did the effect of a full twelve months of increased Missouri electric rates that were effective June 2011 and a change in our unbilled revenue estimate in the third quarter of 2012.

Negative drivers for the twelve months ended 2013 period included increased regulated operating expense, depreciation and amortization expense and the regulatory write off of approximately $3.6 million discussed below.

Factors impacting gross margin and net income for the quarter and twelve months ending March 31, 2013, are presented on a segment basis under Results of Operations below.

The table below sets forth a reconciliation of basic and diluted earnings per share between the three months and twelve months ended March 31, 2012 and March 31, 2013, which is a non-GAAP presentation. The economic substance behind our non-GAAP earnings per share (EPS) measure is to present the after tax impact of significant items and components of the statement of income on a per share basis before the impact of additional stock issuances.

We believe this presentation is useful to investors because the statement of income does not readily show the EPS impact of the various components, including the effect of new stock issuances. This could limit the readers’ understanding of the reasons for the EPS change from the previous year’s EPS. This information is useful to management, and we believe this information is useful to investors, to better understand the reasons for the fluctuation in EPS between the prior and current years on a per share basis.

This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statement of income. We also note that this presentation does not purport to be an alternative to earnings per share determined in accordance with GAAP as a measure of operating performance or any other measure of financial performance presented in accordance with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone. The dilutive effect of additional shares issued included in the table reflects the estimated impact of all shares issued during the periods ended March 31.

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	Three Months Ended			Twelve Months Ended
Earnings Per Share — 2012	$	0.23		$	1.26
Revenues
Electric segment	$	0.13		$	0.06
Gas segment	0.07			0.05
Other segment	0.00			0.00
Total Revenue	0.20			0.11
Electric fuel and purchased power	0.00			0.18
Cost of natural gas sold and transported	(0.05		)	(0.04		)
Margin	0.15			0.25
Operating — electric segment	(0.06		)	(0.14		)
Operating — gas segment	0.00			0.00
Operating — other segment	0.00			(0.01		)
Maintenance and repairs	0.00			0.01
Depreciation and amortization	(0.02		)	(0.01		)
Loss on plant disallowance	(0.03		)	(0.03		)
Other taxes	(0.01		)	(0.02		)
Interest charges	0.01			0.03
AFUDC	0.01			0.03
Change in effective income tax rates	0.01			0.02
Other income and deductions	0.01			0.00
Dilutive effect of additional shares issued	0.00			(0.01		)
Earnings Per Share — 2013	$	0.30		$	1.38

Recent Activities

Regulatory Matters

On February 22, 2013, we filed a Nonunanimous Stipulation and Agreement (Agreement) with the Missouri Public Service Commission (MPSC) which issued an order approving the Agreement on February 27, 2013, effective March 6, 2013. The Agreement provides for an annual increase in base revenues for our Missouri electric customers in the amount of approximately $27.5 million, effective April 1, 2013, and the continuation of the current fuel adjustment mechanism. The Agreement also includes an increase in depreciation rates, recovery of deferred tornado costs over the next ten years and the continuation of tracking mechanisms for expenses related to employee pension, retiree health care, vegetation management, and Iatan 2, Iatan Common and Plum Point operating and maintenance costs. In addition, the Agreement includes a write-off of approximately $3.6 million, consisting of a $2.4 million disallowance for the prudency of certain construction expenditures for Iatan 2 and a $1.2 million regulatory reversal of a prior period gain on sale of our Asbury unit train, which is included in regulated operating expenses. We also agreed not to implement a Missouri general rate increase prior to October 1, 2014. As initially filed on July 6, 2012, we had requested an annual increase in base rates for our Missouri electric customers in the amount of $30.7 million, or 7.56%, the continuation of the fuel adjustment clause, new depreciation rates and the recovery of various expenses. For additional information, see “Rate Matters” below.

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three-month and twelve-month periods ended March 31, 2013, compared to the same periods ended March 31, 2012.

The following table represents our results of operations by operating segment for the applicable periods ended March 31 (in millions):

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	Three Months Ended				Twelve Months Ended
	2013		2012		2013		2012
Electric	$	10.2	$	8.2	$	54.7	$	49.6
Gas	1.9		1.1		2.1		1.6
Other	0.5		0.5		1.7		1.7
Net income	$	12.6	$	9.8	$	58.5	$	52.9

Electric Segment

Gross Margin

As shown in the table below, electric segment gross margin increased approximately $9.0 million during the first quarter of 2013 as compared to the first quarter of 2012 mainly due to increased demand resulting from favorable weather in the first quarter of 2013.

The electric gross margin increased approximately $16.4 million for the twelve months ended March 31, 2013 as compared to the same period in 2012, due to a full twelve months of increased Missouri electric rates that were effective June 2011, improved customer counts, a change in our unbilled revenue estimate in the third quarter of 2012 and a small favorable margin impact due to the colder weather in the first quarter of 2013.

The table below represents our electric gross margins for the applicable periods ended March 31 (dollars in millions):

	Quarter Ended						Twelve Months Ended
	2013			2012			2013			2012
Electric segment revenues	$	128.8		$	119.7		$	519.7		$	515.6
Fuel and purchased power	45.3			45.2			179.0			191.3
Electric segment gross margins	$	83.5		$	74.5		$	340.7		$	324.3
Margin as % of total electric segment revenues	64.8		%	62.2		%	65.6		%	62.9		%

Although a non-GAAP presentation, we believe the presentation of gross margin is useful to investors and others in understanding and analyzing changes in our electric operating performance from one period to the next, and have included the analysis as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Sales and Revenues

Electric operating revenues comprised approximately 84.9% of our total operating revenues during the first quarter of 2013.

The amounts and percentage changes from the prior periods in kilowatt-hour (kWh) sales by major customer class for on-system and off-system sales for the applicable periods ended March 31, were as follows:

	kWh Sales  (in millions)
	First	First			12 Months	12 Months
	Quarter	Quarter	%		Ended	Ended	%
Customer Class	2013	2012	Change(1)		2013	2012	Change(1)
Residential	571.1	476.5	19.8	%	1,945.4	1,867.8	4.2	%
Commercial	359.7	337.8	6.5		1,580.1	1,538.5	2.7
Industrial	240.6	241.7	(0.4	)	1,027.3	1,027.4	0.0
Wholesale on-system	84.4	84.5	0.0		353.1	361.7	(2.4	)
Other(2)	33.0	31.2	5.6		125.9	126.7	(0.6	)
Total on-system sales	1,288.8	1,171.7	10.0		5,031.8	4,922.1	2.2
Off-system	152.3	136.8	11.4		719.6	618.8	16.3
Total kWh Sales	1,441.1	1,308.5	10.1		5,751.4	5,540.9	3.8

(1) Percentage changes are based on actual kWh sales and may not agree to the rounded amounts shown above.

(2) Other kWh sales include street lighting, other public authorities and interdepartmental usage.

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KWh sales for our on-system customers increased 10.0% during the first quarter of 2013 as compared to the first quarter of 2012, primarily due to increased demand resulting from colder weather in the first quarter of 2013. The increase in residential and commercial kWh sales was mainly due to the colder weather. Total heating degree days (the sum of the number of degrees that the daily average temperature for each day during that period was below 65° F) for the first quarter of 2013 were near normal, at only 0.2% more than the 30-year average, although they were 33.9% more than the same period last year when the warmest temperatures on record were recorded. Industrial sales decreased 0.4%.

KWh sales for our on-system customers increased 2.2% during the twelve months ended March 31, 2013, as compared to the same period in 2012, due to improved customer counts and increased demand resulting from colder weather in the first quarter of 2013. Residential and commercial kWh sales increased primarily due to the improved customer counts and favorable weather. Industrial sales decreased slightly.

The amounts and percentage changes from the prior periods in electric segment operating revenues by major customer class for on-system and off-system sales for the applicable periods ended March 31, were as follows:

	Electric Segment Operating Revenues (in millions)
	First		First				12 Months		12 Months
	Quarter		Quarter		%		Ended		Ended		%
Customer Class	2013		2012		Change(1)		2013		2012		Change(1)
Residential	$	61.2	$	54.2	13.0	%	$	221.5	$	216.5	2.3	%
Commercial	34.8		34.4		1.1		159.2		157.5		1.1
Industrial	17.1		18.0		(5.0	)	77.9		80.3		(3.0	)
Wholesale on-system	4.8		4.0		20.2		19.4		18.9		2.7
Other(2)	3.5		3.4		2.2		14.0		14.0		0.2
Total on-system revenues	$	121.4	$	114.0	6.5		$	492.0	$	487.2	1.0
Off-system	3.7		3.2		14.2		16.2		18.6		(12.9	)
Total Revenues from kWh Sales	125.1		117.2		6.7		508.2		505.8		0.5
Miscellaneous Revenues(3)	3.2		2.1		54.5		9.6		8.1		18.5
Total Electric Operating Revenues	$	128.3	$	119.3	7.5		$	517.8	$	513.9	0.8
Water Revenues	0.5		0.4		24.8		1.9		1.7		8.1
Total Electric Segment Operating
Revenues	$	128.8	$	119.7	7.5		$	519.7	$	515.6	0.8

(1) Percentage changes are based on actual revenues and may not agree to the rounded amounts shown above.

(2) Other operating revenues include street lighting, other public authorities and interdepartmental usage.

(3)Miscellaneous revenues include transmission service revenue, late payment fees, renewable energy credit sales, rent, etc.

Revenues for our on-system customers increased $7.4 million during the first quarter of 2013 primarily due to colder weather as compared to record mild weather in the first quarter of 2012. The impact of weather and other related factors increased revenues an estimated $9.3 million. Improved customer counts increased revenues an estimated $1.6 million. Rate changes increased revenues an estimated $1.2 million. These revenue increases were partially offset by a $4.7 million decrease in fuel recovery revenue (and corresponding reduction in fuel expenses, resulting in no net effect on gross margin) from Missouri customers during the first quarter of 2013 compared to the prior year quarter.

Revenues for our on-system customers increased $4.8 million for the twelve months ended March 31, 2013. Rate changes, primarily the June 2011 Missouri rate increase and the January 2012 Kansas rate increase, contributed an estimated $5.0 million to revenues. Improved customer counts increased revenues an estimated $4.9 million. Weather and other related factors increased revenues an estimated $1.7 million. Additionally, a change in our unbilled revenue estimate in the third quarter of 2012 added $3.1 million to revenues. These revenue increases were offset by a $9.9 million decrease in fuel recovery revenue (and corresponding reduction in fuel expenses, resulting in no net effect on gross margin) from Missouri customers during the twelve months ended March 31, 2013 compared to the same period in 2012.

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Off-System Electric Transactions.

In addition to sales to our own customers, we also sell power to other utilities as available, including through the Southwest Power Pool (SPP) Energy Imbalance Services (EIS) market. See “— Competition and Markets” below. The majority of our off-system sales margins are included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and our transmission rider in our Arkansas jurisdiction and generally adjust the fuel and purchased power expense. As a result, nearly all of the off-system sales margin flows back to the customer and has little effect on margin or net income.

Miscellaneous Revenues

Our miscellaneous revenues were $3.2 million for the first quarter of 2013 as compared to $2.0 million for the first quarter of 2012, mainly due to increased transmission revenues.

Our miscellaneous revenues were $9.6 million for the twelve months ended March 31, 2013 as compared to $8.1 million for the same period in 2012, mainly due to increased transmission revenues. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions — Fuel and Purchased Power

The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statements of income for the applicable periods ended March 31, 2013 and 2012.

	Three Months Ended						Twelve Months Ended
(in millions)	2013			2012			2013			2012
Actual fuel and purchased power expenditures	$	47.7		$	40.7		$	180.6		$	186.8
Missouri fuel adjustment recovery (1)	(0.4		)	4.3			(1.2		)	8.6
Missouri fuel adjustment deferral(2)	(1.1		)	1.8			2.4			(2.0		)
Kansas and Oklahoma regulatory adjustments(2)	0.1			0.3			0.7			(0.3		)
SWPA amortization(3)	(0.8		)	(0.7		)	(2.9		)	(2.1		)
Unrealized (gain)/loss on derivatives	(0.2		)	(1.2		)	(0.6		)	0.3
Total fuel and purchased power expense per income statement	$	45.3		$	45.2		$	179.0		$	191.3

(1) A positive amount indicates costs recovered from customers from under recovery in prior deferral periods. A negative amount indicates costs refunded to customers from over recovery in prior deferral periods.

(2)A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers. Missouri amount includes the deferral of additional costs due to construction accounting, which terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

(3) Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010.

Operating Expenses — Other Than Fuel and Purchased Power

The table below shows regulated operating expense increases/(decreases) during the first quarter of 2013 and the twelve months ended March 31, 2013 as compared to the same periods in 2012.

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	Three Months Ended			Twelve Months Ended
(in millions)	2013 vs. 2012			2013 vs. 2012
Transmission and distribution expense	$	0.9		$	2.4
Employee health care expense	0.5			2.3
General labor costs	0.7			1.3
Employee pension expense	0.1			0.8
Regulatory reversal of gain on prior period sale of assets	1.2			1.2
Professional services(1)	(0.2		)	1.6
Steam power other operating expense(2)	(0.1		)	0.8
Other power operation expense	0.1			0.3
Uncollectible accounts	0.1			(0.7		)
Regulatory commission expense	—			(0.6		)
Property insurance	0.2			0.6
Injuries and damages expense	0.3			(0.2		)
Banking fees	(0.3		)	(1.0		)
Other miscellaneous accounts (netted)	0.3			0.3
TOTAL	$	3.8		$	9.1

(1)  The twelve month comparison reflects the transfer of $0.9 million of expenses from Professional Services in July 2011 to regulatory and capital assets per our 2010 Missouri rate case.

(2) The twelve month comparison reflects recognition of expenses of new plants (Iatan and Plum Point) after deferral ended June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

The table below shows maintenance and repairs expense increases/(decreases) during the first quarter of 2013 and the twelve months ended March 31, 2013 compared to the same periods in 2012.

	Three Months Ended			Twelve Months Ended
(in millions)	2013 vs. 2012			2013 vs. 2012
Distribution and transmission maintenance costs	$	(1.1	)	$	(2.6	)
Maintenance and repairs expense at the Asbury plant	0.6			1.5
Maintenance and repairs expense at the SLCC(1)	0.7			1.6
Maintenance and repairs expense at the Iatan plant, Energy Center, Plum Point plant and Riverton plant	0.0			(0.7		)
Other miscellaneous accounts (netted)	(0.2		)	(0.2		)
TOTAL	$	0.0		$	(0.4	)

(1) The twelve month comparison reflects a transformer failure in December 2011.

Depreciation and amortization expense increased approximately $1.1 million (8.2%) during the three months ended March 31, 2013 due to increased plant in service. Depreciation and amortization expense increased approximately $0.6 million (1.2%) during the twelve months ended March 31, 2013. This reflects a decrease in regulatory amortization expense of $2.1 million due to the termination of construction accounting as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case, offset by increased plant in service.

Other taxes increased approximately $0.4 million and $1.3 million during the quarter and twelve month periods ended March 31, 2013, respectively, due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

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Gas Segment

Gas Operating Revenues and Sales

The following table details our natural gas sales for the periods ended March 31:

Total Gas Delivered to Customers

	Three Months Ended				Twelve Months Ended
(bcf sales)	2013	2012	% change		2013	2012	% change
Residential	1.34	0.96	38.8	%	2.38	2.13	12.3	%
Commercial	0.60	0.45	35.6		1.21	1.08	11.4
Industrial(1)	0.03	0.03	26.4		0.07	0.08	(22.3	)
Other(2)	0.02	0.01	40.1		0.03	0.03	11.2
Total retail sales	1.99	1.45	37.6		3.69	3.32	11.1
Transportation sales	1.41	1.22	15.6		4.44	4.26	4.1
Total gas operating sales	3.40	2.67	27.5		8.13	7.58	7.2

(1) The twelve month ended percentage change reflects the transfer of customers from industrial sales to transportation during the first quarter of 2012.

(2) Other includes other public authorities and interdepartmental usage.

Gas retail sales increased 37.6% during the first quarter of 2013 as compared to 2012 primarily due to colder weather during the first quarter of 2013. Heating degree days were 40.9% more in the first quarter of 2013 as compared to the first quarter of 2012 and 3.1% more than the 30-year average. The winter months are normally high sales months for the natural gas business, whose heating season runs from November to March of each year.

Gas retail sales increased 11.1% during the twelve months ended March 31, 2013 as compared to the same period in 2012, primarily reflecting the colder weather in the first quarter of 2013.

The following table details our natural gas revenues for the periods ended March 31:

Operating Revenues and Cost of Gas Sold

	Three Months Ended						Twelve Months Ended
($ in millions)	2013		2012		% change		2013		2012		% change
Residential	$	13.3	$	10.1	31.9	%	$	28.0	$	25.5	9.4	%
Commercial	5.7		4.3		32.8		12.2		11.0		10.6
Industrial(1)	0.2		0.2		23.2		0.5		0.6		(13.8	)
Other(2)	0.2		0.1		33.9		0.3		0.3		8.5
Total retail revenues	$	19.4	$	14.7	32.0		$	41.0	$	37.4	9.4
Other revenues	0.0		0.1		(23.3	)	0.4		0.5		(17.7	)
Transportation revenues(1)	1.1		0.9		14.3		3.3		3.2		2.8
Total gas operating revenues	$	20.5	$	15.7	30.7		$	44.7	$	41.1	8.6
Cost of gas sold	11.9		8.6		39.0		22.0		19.3		13.9
Gas operating revenues over cost of gas in rates (margin)	$	8.6	$	7.1	20.6		$	22.7	$	21.8	3.9

(1) The twelve month ended percentage change reflects the transfer of customers from industrial sales to transportation during the first quarter of 2012.

(2) Other includes other public authorities and interdepartmental usage.

During the first quarter of 2013, gas segment revenues increased approximately $4.8 million as compared to the first quarter of 2012, mainly due to increased sales resulting from colder weather during the first quarter of 2013. Our margin (defined as gas operating revenues less cost of gas in rates) was $1.5 million more in the first quarter of 2013 as compared to the same period in 2012, due to the weather impact.

During the twelve months ended March 31, 2013, gas segment revenues increased approximately $3.5 million as compared to the same period in 2012, mainly due to the increase in sales in the first quarter of 2013. Our margin for the twelve months ended March 31, 2013 increased $0.9 million as compared to the same period in 2012.

We have a PGA clause in place that allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs

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recovered through the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of March 31, 2013, we had unrecovered purchased gas costs of $0.8 million recorded as a current regulatory asset and over recovered purchased gas costs of $1.9 million recorded as a non-current regulatory liability.

Operating Revenue Deductions

Quarter. Total other operating expenses in the first quarter of 2013 were $2.2 million, which is virtually the same as in the first quarter of 2012.

Our gas segment had net income of $1.9 million for the first quarter of 2013 as compared to $1.1 million for the first quarter of 2012.

Twelve Months Ended. Total other operating expenses were $8.4 million for both the twelve months ended March 31, 2013 and the twelve months ended March 31, 2012.

Our gas segment had net income of $2.1 million for the twelve months ended March 31, 2013 as compared to $1.6 million for the twelve months ended March 31, 2012.

Consolidated Company

Income Taxes

The following table shows the changes in our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended March 31:

	Three Months Ended						Twelve Months Ended
	2013			2012			2013			2012
Consolidated provision for income taxes	$	7.5		$	6.2		$	35.4		$	33.3
Consolidated effective federal and state income tax rates	37.2		%	38.7		%	37.7		%	38.6		%

See Note 12 of “Notes to Consolidated Financial Statements (Unaudited)” for more information and discussion concerning our income tax provision and effective tax rates.

Nonoperating Items

The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended March 31. AFUDC increased during all periods presented in 2013 reflecting the environmental retrofit project at our Asbury plant.

	Three Months Ended				Twelve Months Ended
($ in millions)	2013		2012		2013		2012
Allowance for equity funds used during construction	$	0.5	$	0.1	$	1.7	$	0.4
Allowance for borrowed funds used during construction	0.3		—		1.0		0.2
Total AFUDC	$	0.8	$	0.1	$	2.7	$	0.6

Total interest charges on long-term and short-term debt for the periods ended March 31, are shown below. The change in long-term debt interest for 2013 compared to 2012 reflects the redemption on April 1, 2012 of all $74.8 million aggregate principal amount of our First Mortgage Bonds, 7.00% Series due 2024, the redemption of all $5.2 million of our First Mortgage Bonds, 5.20% Pollution Control Series due 2013, and all $8.0 million of our First Mortgage Bonds, 5.30% Pollution Control Series due 2013. These bonds were replaced by a private placement of $88.0 million aggregate principal amount of 3.58% First Mortgage Bonds due April 2, 2027. The first settlement of $38.0 million occurred on April 2, 2012 and the second settlement of $50.0 million occurred on June 1, 2012.  The changes in short-term debt interest primarily reflect higher levels of borrowing.

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	Interest Charges ($ in millions)
	3 Months			3 Months				12 Months		12 Months
	Ended			Ended		%		Ended		Ended			%
	2013			2012		Change		2013		2012			Change
Long-term debt interest	$	10.0		$	10.7	(6.6	)%	$	39.5	$	42.6		(7.3	)%
Short-term debt interest	0.0			0.0		58.8		0.2		0.1			>100.0
Iatan 1 and 2 carrying charges*	0.0			0.0		26.8		0.1		(0.9		)	>100.0
Other interest	0.2			0.2		(5.7	)	1.0		1.0			(0.4	)
Total interest charges	$	10.2	��	$	10.9	(6.3	)	$	40.8	$	42.8		(4.6	)

* The twelve month ended comparison reflects deferred Iatan 1and Iatan 2 carrying charges to reflect construction accounting in accordance with our agreement with the MPSC. Deferral ended when the plants were placed in rates. See Note 3 and Rate Matters below for additional information regarding carrying charges.

RATE MATTERS

We continually assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.

Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for us to earn a reasonable return on “rate base.” “Rate base” is generally determined by reference to the original cost (net of accumulated depreciation and amortization) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation, amortization and retirement of utility plant or write-off’s as ordered by the utility commissions. In general, a request of new rates is made on the basis of a “rate base” as of a date prior to the date of the request and allowable operating expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process provides recovery of some future changes in rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag (commonly referred to as “regulatory lag”) between the time we incur costs and the time when we can start recovering the costs through rates.

The following table sets forth information regarding electric and water rate increases since January 1, 2010:

Jurisdiction	Date Requested	Annual Increase Granted		Percent Increase Granted		Date Effective
Missouri — Electric	July 6, 2012	$	27,500,000	6.78	%	April 1, 2013
Missouri — Water	May 21, 2012	$	450,000	25.5	%	November 23, 2012
Missouri — Electric	September 28, 2010	$	18,700,000	4.70	%	June 15, 2011
Missouri — Electric	October 29, 2009	$	46,800,000	13.40	%	September 10, 2010
Kansas — Electric	June 17, 2011	$	1,250,000	5.20	%	January 1, 2012
Kansas — Electric	November 4, 2009	$	2,800,000	12.40	%	July 1, 2010
Oklahoma — Electric	June 30, 2011	$	240,722	1.66	%	January 4, 2012
Oklahoma — Electric	January 28, 2011	$	1,063,100	9.32	%	March 1, 2011
Oklahoma — Electric	March 25, 2010	$	1,456,979	15.70	%	September 1, 2010
Arkansas - Electric	August 19, 2010	$	2,104,321	19.00	%	April 13, 2011
Missouri — Gas	June 5, 2009	$	2,600,000	4.37	%	April 1, 2010

On February 22, 2013, we filed a Nonunanimous Stipulation and Agreement (Agreement) with the MPSC which issued an order approving the Agreement on February 27, 2013, effective March 6, 2013. The Agreement provides for an annual increase in base revenues for our Missouri electric customers in the amount of approximately $27.5 million, effective April 1, 2013, and the continuation of the current fuel adjustment mechanism. The Agreement also includes an increase in depreciation rates, recovery of deferred tornado costs over the next ten years and the continuation of tracking mechanisms for expenses related to employee pension, retiree health care, vegetation management, and Iatan 2, Iatan Common and Plum Point operating and maintenance costs.  In addition, the Agreement includes a write-off of approximately $3.6 million, consisting of a $2.4 million disallowance

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for the prudency of certain construction expenditures for Iatan 2 and a $1.2 million regulatory reversal of a prior period gain on sale of our Asbury unit train, which is included in regulated operating expenses. We also agreed not to implement a Missouri general rate increase prior to October 1, 2014.

As initially filed on July 6, 2012, we requested an annual increase in base rates for our Missouri electric customers in the amount of $30.7 million, or 7.56%, and the continuation of the fuel adjustment clause. This request was primarily designed to recover operation and maintenance expenses and capital costs associated with the May 22, 2011 tornado, Southwest Power Pool transmission charges allocated to us, operating systems replacement costs for new software systems, vegetation management costs, new depreciation rates and amortization of a regulatory asset related to the tax benefits of cost of removal, the balance of which was approximately $9.6 million at December 31, 2012.

Our other rate cases, as we reported in our Annual Report on Form 10-K for the year ended December 31, 2012, remain unchanged. See Note 3, “Regulatory Matters” in our Annual Report on Form 10-K for the year ended December 31, 2012 for additional information

COMPETITION AND MARKETS

See Note 3, “Regulatory Matters — Competition and Markets” in our Annual Report on Form 10-K for the year ended December 31, 2012.

LIQUIDITY AND CAPITAL RESOURCES

Overview.Our primary sources of liquidity are cash provided by operating activities, short-term borrowings under our commercial paper program (which is supported by our credit facilities) and borrowings from our unsecured revolving credit facility. As needed, we raise funds from the debt and equity capital markets to fund our liquidity and capital resource needs.

Our issuance of various securities, including equity, long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions and the SEC. We estimate that internally generated funds (funds provided by operating activities less dividends paid) will provide 68% of the funds required for the remainder of 2013 for our budgeted capital expenditures (as discussed in “Capital Requirements and Investing Activities” below). We believe the amounts available to us under our credit facilities and the issuance of debt and equity securities together with the cash provided by operating activities, will allow us to meet our needs for working capital, pension contributions, our continuing construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the timing of our construction programs and other factors. See Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012 for additional information on items that could impact our liquidity and capital resource requirements. The following table provides a summary of our operating, investing and financing activities for the quarters ended March 31:

Summary of Cash Flows

	Quarter Ended March 31,
(in millions)	2013			2012			Change
Cash provided by/(used in):
Operating activities	$	44.1		$	39.1		$	5.0
Investing activities	(35.2		)	(31.0		)	(4.2		)
Financing activities	(9.1		)	(11.2		)	2.1
Net change in cash and cash equivalents	$	(0.2	)	$	(3.1	)	$	2.9

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Cash flow from Operating Activities

We prepare our statement of cash flows using the indirect method. Under this method, we reconcile net income to cash flows from operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period. These reconciling items include depreciation and amortization, pension costs, deferred income taxes, equity AFUDC, changes in commodity risk management assets and liabilities and changes in the consolidated balance sheet for working capital from the beginning to the end of the period.

Period-over-period changes in our operating cash flows are attributable primarily to working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas and coal purchases, the effects of deferred fuel recoveries and the size and timing of pension contributions. The increase or decrease in natural gas prices directly impacts the cost of gas stored in inventory.

First Quarter 2013 Compared to 2012.  During the first quarter of 2013, our net cash flows provided from operating activities was $44.1 million, an increase of $5.0 million or 12.7% from 2012. This change resulted from the following:

·Changes in net income - $2.8 million.

·Reduced pension contributions net of expense accruals - $2.4 million.

·Loss on regulatory plant disallowance - $2.4 million.

·Regulatory reversal of a prior period gain on the sale of assets - $1.2 million.

·Changes related to fuel inventories for both electric and gas segments - $6.8 million.

·Lower fuel related amortizations partially offset by increased plant in service depreciation - $(4.0) million

·Estimates of unbilled accounts receivable - $(6.4) million.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities increased $4.2 million during the first quarter of 2013 as compared to the first quarter of 2012.

Our capital expenditures incurred totaled approximately $41.4 million during the first quarter of 2013 compared to $34.7 million in the first quarter of 2012. The increase was primarily the result of an increase in electric plant additions and replacements, mainly due to the environmental retrofit in progress at our Asbury plant.

A breakdown of the capital expenditures for the quarters ended March 31, 2013 and 2012 is as follows:

	Capital Expenditures
(in millions)	2013			2012
Distribution and transmission system additions	$	12.1		$	12.9
New Generation — Iatan 2	0.2			0.8
Additions and replacements — electric plant	25.9			10.6
Gas segment additions and replacements	0.5			0.6
Storms	0.0			3.5
Transportation	0.2			0.3
Other (including retirements and salvage - net) (1)	2.1			5.0
Subtotal	41.0			33.7
Non-regulated capital expenditures (primarily fiber optics)	0.4			1.0
Subtotal capital expenditures incurred (2)	41.4			34.7
Adjusted for capital expenditures payable (3)	(3.6		)	(3.7		)
Total cash outlay	$	37.8		$	31.0

(1) Other includes equity AFUDC of $(0.5) for 2013 and none for 2012.

(2) Expenditures incurred represent the total cost for work completed for the projects during the reporting period. Discussion of capital expenditures throughout this 10-Q is presented on this basis. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

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(3) The amount of expenditures paid/(unpaid) at the end of the reporting period to adjust to actual cash outlay reflected in the Investing Activities section of the Statement of Cash Flows.

Approximately 88% of our cash requirements for capital expenditures during the first quarter of 2013 were satisfied from internally generated funds (funds provided by operating activities less dividends paid).

We estimate that internally generated funds will provide approximately 68% of the funds required for the remainder of our budgeted 2013 capital expenditures. We intend to utilize short-term debt to finance any additional amounts needed beyond those provided by operating activities for such capital expenditures. If additional financing is needed, we intend to utilize a combination of debt and equity securities. For further information see Note 6 of “Notes to Consolidated Financial Statements (Unaudited).”

Financing Activities

First quarter 2013 compared to 2012.

Our net cash flows used in financing activities was $9.1 million in the first quarter of 2013, a decrease of $2.1 million as compared to the first quarter of 2012, primarily due to the following:

·We repaid $1.0 million in short-term debt in the first quarter 2013 as compared to borrowing $10.5 million in the first quarter of 2012, which provided $9.5 million less cash when comparing 2013 to 2012.

·We repaid $13.2 million of first mortgage bonds in the first quarter of 2012 compared to no repayments or borrowings in the first quarter of 2013.

On October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due 2033 and $120.0 million of 4.32% First Mortgage Bonds due 2043. The delayed settlement is anticipated to occur on or about May 30, 2013, subject to customary closing conditions. We expect to use the proceeds from the sale of the bonds to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013 with the remaining proceeds to be used for general corporate purposes. The bonds will be issued under the EDE Mortgage.

Shelf Registration

We have a $400.0 million shelf registration statement with the SEC, effective February 7, 2011, covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. We have received regulatory approval for the issuance of securities under this shelf from all four states in our electric service territory, but we may only issue up to $250.0 million of such securities in the form of first mortgage bonds, of which $12.0 million would remain available after giving effect to the $150.0 million of new first mortgage bonds to be issued on or about May 30, 2013. We plan to use proceeds from offerings made pursuant to this shelf to fund capital expenditures, refinancings of existing debt or general corporate needs during the three-year effective period.

Credit Agreements

On January 17, 2012, we entered into the Third Amended and Restated Unsecured Credit Agreement which amended and restated our Second Amended and Restated Unsecured Credit Agreement dated January 26, 2010. This agreement extended the termination date of the revolving credit facility from January 26, 2013 to January 17, 2017. The agreement also removed the letter of credit facility and includes a swingline loan facility with a $15 million swingline loan sublimit. The aggregate amount of the revolving credit commitments remains $150 million, inclusive of the $15 million swingline loan sublimit. In addition, the pricing and fees under the facility were amended. Interest on borrowings under the facility accrues at a rate equal to, at our option, (i) the highest of (A) the bank’s prime commercial rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, plus a margin or (ii) one month, two month or three month LIBOR, in each case,

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plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility is 1.25%. A facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings, which fee is currently 0.25%. In addition, upon entering into the amended and restated facility, we paid an upfront fee to the revolving credit banks of $262,500 in the aggregate. There were no other material changes to the terms of the facility.

The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of March 31, 2013, we are in compliance with these ratios. Our total indebtedness is 49.7% of our total capitalization as of March 31, 2013 and our EBITDA is 5.0 times our interest charges. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at March 31, 2013. However, $23.0 million was used to back up our outstanding commercial paper.

EDE Mortgage Indenture

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1.0 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended March 31, 2013 would permit us to issue approximately $628.4 million of new first mortgage bonds based on this test with an assumed interest rate of 5.5%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At March 31, 2013, we had retired bonds and net property additions which would enable the issuance of at least $794.5 million principal amount of bonds if the annual interest requirements are met. As of March 31, 2013, we are in compliance with all restrictive covenants of the EDE Mortgage.

EDG Mortgage Indenture

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300.0 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG’s ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1.0. As of March 31, 2013, this test would allow us to issue approximately $13.3 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%.

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Currently, our corporate credit ratings and the ratings for our securities are as follows:

	Fitch	Moody’s	Standard & Poor’s
Corporate Credit Rating	n/r*	Baa2	BBB
EDE First Mortgage Bonds	BBB+	A3	A-
Senior Notes	BBB	Baa2	BBB
Commercial Paper	F3	P-2	A-2
Outlook	Stable	Stable	Stable

*Not rated

On March 6, 2013, Standard & Poor’s upgraded our corporate credit rating to BBB from BBB-, senior secured debt to A- from BBB+, senior unsecured debt to BBB from BBB- and our commercial paper rating to A-2 from A-3. Standard & Poor’s outlook for Empire is stable. On May 26, 2011 after the May 22, 2011 tornado, and again on April 25, 2012, Moody’s reaffirmed all of our ratings. On March 24, 2011, Fitch revised our commercial paper rating from F2 to F3 and reaffirmed our other ratings. The rating action was not based on a specific action or event on our part, but reflected their traditional linkage of long-term and short-term Issuer Default Ratings. On May 29, 2012, Fitch reaffirmed our ratings.

A security rating is not a recommendation to buy, sell or hold securities. Each rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered independently of all other ratings.

CONTRACTUAL OBLIGATIONS

Our contractual obligations have not materially changed at March 31, 2013, compared to December 31, 2012. See “Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2012.

DIVIDENDS

Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price.

In response to the expected loss of revenues resulting from the May 22, 2011 tornado, our level of retained earnings and other relevant factors, our Board of Directors suspended our quarterly dividend for the third and fourth quarters of 2011. On February 2, 2012, the Board of Directors re-established the dividend and declared a quarterly dividend of $0.25 per share on common stock payable on March 15, 2012 to holders of record as of March 1, 2012. Dividends were paid during all four quarters of 2012. As of March 31, 2013, our retained earnings balance was $49.1 million, compared to $33.0 million as of March 31, 2012 and $47.1 million as of December 31, 2012, after paying out $10.6 million in dividends during the first quarter of 2013. On April 25, 2013, the Board of Directors declared a quarterly dividend of $0.25 per share on common stock payable June 17, 2013 to holders of record as of June 3, 2013.

Our diluted earnings per share were $0.30 for the quarter ended March 31, 2013 and were $1.32 and $1.31 for the years ended December 31, 2012 and 2011, respectively. Dividends paid per share were $0.25 for the three months ended March 31, 2013, $1.00 for the year ended December 31, 2012 and $0.64 for the year ended December 31, 2011.

Under Kansas corporate law, our Board of Directors may only declare and pay dividends out of our surplus or, if there is no surplus, out of our net profits for the fiscal year in which the dividend is declared or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus accumulated other comprehensive income/(loss), net of income tax. However, Kansas law does permit, under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value to surplus. In addition, Section 305(a) of the Federal Power Act (FPA) prohibits

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the payment by a utility of dividends from any funds “properly included in capital account”. There are no additional rules or regulations issued by the FERC under the FPA clarifying the meaning of this limitation. However, several decisions by the FERC on specific dividend proposals suggest that any determination would be based on a fact-intensive analysis of the specific facts and circumstances surrounding the utility and the dividend in question, with particular focus on the impact of the proposed dividend on the liquidity and financial condition of the utility.

In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. On June 9, 2011, we amended the EDE Mortgage in order to provide us with additional flexibility to pay dividends to our shareholders by permitting the payment of any dividend or distribution on, or purchase of, shares of its common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied with the provisions of the EDE Mortgage and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1.

OFF-BALANCE SHEET ARRANGEMENTS

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources, other than operating leases entered into in the normal course of business.

CRITICAL ACCOUNTING POLICIES

See “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2012 for a discussion of additional critical accounting policies. There were no changes in these policies in the quarter ended March 31, 2013.

RECENTLY ISSUED ACCOUNTING STANDARDS

See Note 2 of “Notes to Consolidated Financial Statements (Unaudited)”.

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

Our fuel procurement activities involve primary market risk exposures, including commodity price risk and credit risk. Commodity price risk is the potential adverse price impact related to the fuel procurement for our generating units. Credit risk is the potential adverse financial impact resulting from non-performance by a counterparty of its contractual obligations. Additionally, we are exposed to interest rate risk which is the potential adverse financial impact related to changes in interest rates.

Market Risk and Hedging Activities.

Prices in the wholesale power markets often are extremely volatile. This volatility impacts our cost of power purchased and our participation in energy trades. If we were unable to generate an adequate supply of electricity for our customers, we would attempt to purchase power from others. Such supplies are not always available. In addition, congestion on the transmission system can limit our ability to make purchases from (or sell into) the wholesale markets.

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We engage in physical and financial trading activities with the goals of reducing risk from market fluctuations. In accordance with our established Energy Risk Management Policy, which typically includes entering into various derivative transactions, we attempt to mitigate our commodity market risk. Derivatives are utilized to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

Commodity Price Risk.

We are exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas, and electricity and employ established policies and procedures to manage the risks associated with these market fluctuations, including utilizing derivatives.

We satisfied 65.6% of our 2012 generation fuel supply need through coal. This includes the remaining coal used at Riverton as part of its transition to natural gas. Approximately 96% of our 2012 coal supply was Western coal. We have contracts and binding proposals to supply a portion of the fuel for our coal plants through 2015. These contracts satisfy approximately 100% of our anticipated fuel requirements for 2013, 58% for 2014 and 26% for our 2015 requirements for our Asbury coal plant. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to manage our costs to avoid volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and improve predictability. As of March 31, 2013, 60%, or 4.7 million Dths’s, of our anticipated volume of natural gas usage for our electric operations for the remainder of 2013 is hedged.

Based on our expected natural gas purchases for our electric operations for the next twelve months, if average natural gas prices should increase 10% more than the price at March 31, 2013, our natural gas cost would increase by approximately $1.9 million based on our March 31, 2013 total hedged positions for the next twelve months. However, this is probable of recovery through fuel adjustment mechanisms in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel costs.

We attempt to mitigate a portion of our natural gas price risk associated with our gas segment using physical forward purchase agreements, storage and derivative contracts. As of March 31, 2013, we have 0.2 million Dths in storage on the three pipelines that serve our customers. This represents 10% of our storage capacity.

See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

Credit Risk.

In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” regarding agreements containing credit risk contingent features. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Conversely, we are required to post collateral with counterparties at certain thresholds, which is typically the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent counterparty funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at March 31, 2013 and December 31, 2012. There were no margin deposit liabilities at these dates.

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(in millions)	March 31, 2013		December 31, 2012
Margin deposit assets	$	3.1	$	4.2

Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a small group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Below is a table showing our net credit exposure at March 31, 2013, reflecting that our counterparties are exposed to Empire for the net unrealized mark-to-market losses for physical forward and financial natural gas contracts carried at fair value.

(in millions)
Net unrealized mark-to-market losses for physical forward natural gas contracts	$	4.5
Net unrealized mark-to-market losses for financial natural gas contracts	4.0
Net credit exposure	$	8.5

The $4.0 million net unrealized mark-to-market loss for financial natural gas contracts is comprised of $4.1 million that our counterparties are exposed to Empire for unrealized losses and $0.1 million that Empire is exposed to one counterparty. We are holding no collateral from any counterparty since we are below the $10.0 million mark-to-market collateral threshold in our agreements. As noted above, as of March 31, 2013, we have $3.1 million on deposit for NYMEX contract exposure to Empire, of which $2.2 million represents our collateral requirement. In addition, if NYMEX gas prices decreased 25% from their March 31, 2013 levels, we would be required to post an additional $6.9 million in collateral. If these prices increased 25%, our collateral requirement would decrease $1.1 million. Our other counterparties would not be required to post collateral with Empire.

We sell electricity and gas and provide distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers. Credit risk associated with trade accounts receivable from energy customers is limited due to the large number of customers. In addition, we enter into contracts with various companies in the energy industry for purchases of energy-related commodities, including natural gas in our fuel procurement process.

Interest Rate Risk.

We are exposed to changes in interest rates as a result of financing through our issuance of commercial paper and other short-term debt. We manage our interest rate exposure by limiting our variable-rate exposure (applicable to commercial paper and borrowings under our unsecured credit agreement) to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates.

If market interest rates average 1% more in 2013 than in 2012, our interest expense would increase, and income before taxes would decrease by less than $0.6 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2012. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

Item 4.   Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2013.

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There have been no changes in our internal control over financial reporting that occurred during the first quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

See Note 7 of “Notes to Consolidated Financial Statements (Unaudited)” under “Legal Proceedings”, which description is incorporated herein by reference

Item 1A.  Risk Factors.

There have been no material changes to the factors disclosed in Part I, Item 1-A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 5.  Other Information.

For the twelve months ended March 31, 2013, our ratio of earnings to fixed charges was 2.98x.  See Exhibit (12) hereto.

Item 6.  Exhibits.

(a)Exhibits.

(12) Computation of Ratio of Earnings to Fixed Charges.

(31)(a) Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(31)(b) Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32)(a) Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

(32)(b) Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

(101) The following financial information from The Empire District Electric Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2013, filed with the SEC on May 9, 2013, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for the three and twelve month periods ended March 31, 2013 and 2012, (ii) the Consolidated Balance Sheets at March 31, 2013 and December 31, 2012, (iii) the Consolidated Statements of Cash Flows for the three-month periods ended March 31, 2013 and 2012, and (iv) Notes to Consolidated Financial Statements.**

*This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company for purposes of Section 18 or any other provision of the Securities Exchange Act of 1934, as amended.

**Pursuant to Rule 406T of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report on Form 10-Q shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed incorporated by reference into, or part of a registration statement, prospectus or other document filed under the Securities Act of 1933, as amended or the Exchange Act of 1934, as amended except as shall be expressly set forth by specific reference in such filings.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	THE EMPIRE DISTRICT ELECTRIC COMPANY
	Registrant
	By	/s/ Laurie A. Delano
		Laurie A. Delano
		Vice President — Finance and Chief Financial Officer
	By	/s/ Robert W. Sager
		Robert W. Sager
		Controller, Assistant Secretary and Assistant Treasurer
May 9, 2013

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